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 September 30, 2016

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 or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

	Large accelerated filer	Accelerated filer	Non- accelerated filer	Smaller reporting company
DPL Inc.	o	o	x	o
The Dayton Power and Light Company	o	o	x	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 common stock of The Dayton Power and Light Company is owned by DPL Inc.

As of November 3, 2016, 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 September 30, 2016

		Page No.
Glossary of Terms		5
Forward-Looking Statements		7
Part I Financial Information
Item 1	Financial Statements – DPL Inc. and The Dayton Power and Light Company (Unaudited)
	DPL Inc.
	Condensed Consolidated Statements of Operations	10
	Condensed Consolidated Statements of Comprehensive Income / (Loss)	11
	Condensed Consolidated Balance Sheets	12
	Condensed Consolidated Statements of Cash Flows	13
	Notes to Condensed Consolidated Financial Statements	14
	The Dayton Power and Light Company
	Condensed Statements of Operations	40
	Condensed Statements of Comprehensive Income / (Loss)	41
	Condensed Balance Sheets	42
	Condensed Statements of Cash Flows	43
	Notes to Condensed Financial Statements	44
Item 2	Management’s Discussion and Analysis of Financial Condition and Operations	65
	Electric Sales and Customers	89
Item 3	Quantitative and Qualitative Disclosures about Market Risk	89
Item 4	Controls and Procedures	89

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DPL Inc. and The Dayton Power and Light Company

Table of Contents (cont.)

Quarterly Report on Form 10-Q

Quarter Ended September 30, 2016

		Page No.
Part II Other Information
Item 1	Legal Proceedings	89
Item 1A	Risk Factors	90
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	90
Item 3	Defaults Upon Senior Securities	90
Item 4	Mine Safety Disclosures	90
Item 5	Other Information	90
Item 6	Exhibits	91
Other
	Signatures	92

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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.
CAIR	Clean Air Interstate Rule
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.
CRES	Competitive Retail Electric Service
CSAPR	Cross-State Air Pollution Rule
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
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 an amended application on October 11, 2016.
ESP 3	ESP filed with the PUCO by DP&L on February 22, 2016
FASC	Financial Accounting Standards Board (FASB) Accounting Standards Codification
FERC	Federal Energy Regulatory Commission
Form 10-K	DPL’s and DP&L’s combined Annual Report on Form 10-K for the fiscal year ended December 31, 2015, which was filed on February 23, 2016
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
GAAP	Generally Accepted Accounting Principles in the United States of America

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GLOSSARY OF TERMS (cont.)
Term	Definition
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
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NOx	Nitrogen Oxide
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
PRP	Potentially Responsible Party
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
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
USEPA	U.S. Environmental Protection Agency
USF	The Universal Service Fund is a statewide program which provides qualified low-income customers in Ohio with income-based bills and energy efficiency education programs
U.S. SBU	U. S. Strategic Business Unit, AES’ reporting unit covering the businesses in the United States, including DPL
VIE	Variable Interest Entity is an entity in which the investor holds a controlling interest that is not based on the majority of voting rights.

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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;

• increased competition in the retail generation market;

• 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, 2015 and the “Management’s Discussion and Analysis of Financial Condition and Results of

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Operations” section in such report and in our Quarterly Report on Form 10-Q for the quarters ended June 30, and March 31, 2016 and this Quarterly Report on Form 10-Q for a more detailed discussion of the foregoing and certain other factors that could cause actual results to differ materially from those reflected in such forward-looking statements and that should be considered in evaluating our outlook.

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

COMPANY WEBSITES

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

Part I – Financial Information

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

Item 1 – Financial Statements

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FINANCIAL STATEMENTS

DPL INC.

9

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
	Three months ended September 30,						Nine months ended September 30,
$ in millions	2016			2015			2016			2015
Revenues	$	389.3		$	403.3		$	1,081.6		$	1,252.1
Cost of revenues:
Fuel	78.9			71.4			206.0			202.2
Purchased power	111.7			144.9			330.5			458.5
Total cost of revenues	190.6			216.3			536.5			660.7
Gross margin	198.7			187.0			545.1			591.4
Operating expenses:
Operation and maintenance	91.5			95.8			257.2			267.4
Depreciation and amortization	30.9			33.8			100.3			100.9
General taxes	21.6			21.7			64.2			66.7
Fixed-asset impairment	—			—			235.5			—
Other	(0.7		)	0.2			(0.6		)	0.4
Total operating expenses	143.3			151.5			656.6			435.4
Operating income / (loss)	55.4			35.5			(111.5		)	156.0
Other income / (expense), net
Investment income	0.1			0.1			0.3			0.1
Interest expense	(27.0		)	(28.9		)	(79.3		)	(90.3		)
Charge for early retirement of debt	(0.5		)	(2.1		)	(3.1		)	(2.1		)
Other expense	(0.2		)	(0.5		)	(0.9		)	(1.2		)
Total other expense, net	(27.6		)	(31.4		)	(83.0		)	(93.5		)
Earnings / (loss) from continuing operations before income taxes	27.8			4.1			(194.5		)	62.5
Income tax expense / (benefit) from continuing operations	12.7			(1.4		)	(75.0		)	15.4
Net income / (loss) from continuing operations	15.1			5.5			(119.5		)	47.1
Discontinued operations (Note 13)
Income / (loss) from discontinued operations	—			4.9			(0.7		)	10.1
Gain from disposal of discontinued operations	—			—			49.2			—
Income tax expense / (benefit) for discontinued operations	—			1.8			18.9			(1.8		)
Discontinued operations	—			3.1			29.6			11.9
Net income / (loss)	$	15.1		$	8.6		$	(89.9	)	$	59.0

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
	Three months ended September 30,						Nine months ended September 30,
$ in millions	2016			2015			2016			2015
Net income / (loss)	$	15.1		$	8.6		$	(89.9	)	$	59.0
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax (expense) / benefit of $0.0, $0.1, $(0.1) and $0.1 for each respective period	0.1			(0.3		)	0.2			(0.2		)
Derivative activity:
Change in derivative fair value, net of income tax expense of $(5.2), $(4.4), $(12.3) and $(5.4) for each respective period	9.5			7.8			22.4			9.6
Reclassification to earnings, net of income tax benefit of $3.0, $1.1, $13.8 and $1.6 for each respective period	(5.5		)	(2.0		)	(24.4		)	(3.4		)
Total change in fair value of derivatives	4.0			5.8			(2.0		)	6.2
Pension and postretirement activity:
Reclassification to earnings, net of income tax expense of $0.0, $0.0, $(0.1) and $(0.4) for each respective period	—			0.1			0.1			(0.1		)
Other comprehensive income / (loss)	4.1			5.6			(1.7		)	5.9
Net comprehensive income / (loss)	$	19.2		$	14.2		$	(91.6	)	$	64.9

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
	September 30,			December 31,
$ in millions	2016			2015
ASSETS
Current assets:
Cash and cash equivalents	$	121.8		$	32.4
Restricted cash	11.6			92.7
Accounts receivable, net (Note 2)	134.9			120.9
Inventories (Note 2)	80.0			109.1
Taxes applicable to subsequent years	19.7			81.2
Regulatory assets, current	—			14.4
Other prepayments and current assets	37.7			44.5
Assets held for sale, current	—			62.2
Total current assets	405.7			557.4
Property, plant & equipment:
Property, plant & equipment	2,701.2			2,909.0
Less: Accumulated depreciation and amortization	(479.6		)	(432.3		)
	2,221.6			2,476.7
Construction work in process	112.1			85.0
Total net property, plant & equipment	2,333.7			2,561.7
Other non-current assets:
Regulatory assets, non-current	186.9			179.9
Intangible assets, net of amortization	0.9			5.0
Other deferred assets	23.2			20.7
Total other non-current assets	211.0			205.6
Total assets	$	2,950.4		$	3,324.7
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt (Note 6)	$	79.2		$	572.8
Accounts payable	87.4			97.5
Accrued taxes	186.7			142.4
Accrued interest	35.5			21.4
Security deposits	14.6			15.2
Regulatory liabilities, current	44.7			24.4
Insurance and claims costs	5.9			5.9
Other current liabilities	76.1			54.5
Deposit received on sale of DPLER	—			75.5
Liabilities held for sale, current	—			1.6
Total current liabilities	530.1			1,011.2
Non-current liabilities:
Long-term debt (Note 6)	1,834.8			1,420.5
Deferred taxes	463.1			568.7
Taxes payable	1.6			84.1
Regulatory liabilities, non-current	129.9			127.0
Pension, retiree and other benefits	80.5			87.1
Other deferred credits	87.5			88.3
Total non-current liabilities	2,597.4			2,375.7
Redeemable preferred stock of subsidiary (Note 9)	—			18.4
Commitments and contingencies (Note 10)
Common shareholder's equity:
Common stock:
1,500 shares authorized; 1 share issued and outstanding at September 30, 2016 and December 31, 2015	—			—
Other paid-in capital	2,232.8			2,237.7
Accumulated other comprehensive income	15.7			17.4
Accumulated deficit	(2,425.6		)	(2,335.7		)
Total common shareholder's equity	(177.1		)	(80.6		)
Total liabilities and shareholder's equity	$	2,950.4		$	3,324.7

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine months ended September 30,
$ in millions	2016			2015
Cash flows from operating activities:
Net income / (loss)	$	(89.9	)	$	59.0
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Depreciation and amortization	100.3			104.1
Amortization of debt market value adjustments	0.1			(1.1		)
Charge for early redemption of debt	3.1			2.1
Deferred income taxes	(101.4		)	(20.5		)
Fixed-asset impairment	235.5			—
Gain on sale of business	(49.2		)	—
Changes in certain assets and liabilities:
Accounts receivable	23.6			48.8
Inventories	29.1			3.1
Prepaid taxes	0.2			(0.6		)
Taxes applicable to subsequent years	61.5			58.2
Deferred regulatory costs, net	19.5			27.6
Accounts payable	(10.2		)	(15.9		)
Accrued taxes payable	(34.2		)	(39.2		)
Accrued interest payable	13.9			3.7
Security deposits	(0.6		)	19.4
Pension, retiree and other benefits	(2.2		)	1.0
Other	(0.5		)	10.7
Net cash provided by operating activities	198.6			260.4
Cash flows from investing activities:
Capital expenditures	(109.8		)	(93.5		)
Proceeds from sale of business	75.5			1.3
Insurance proceeds	5.2			—
Purchase of renewable energy credits	(0.3		)	(0.6		)
Decrease in restricted cash	5.5			3.2
Other investing activities, net	0.8			0.4
Net cash used in investing activities	(23.1		)	(89.2		)
Cash flows from financing activities:
Payments of deferred financing costs	(8.0		)	(5.6		)
Issuance of long-term debt, net of discount	442.8			325.0
Retirement of long-term debt	(520.8		)	(474.5		)
Borrowings from revolving credit facilities	—			70.0
Repayment of borrowings from revolving credit facilities	—			(60.0		)
Other financing activities, net	(0.1		)	(0.1		)
Net cash used in financing activities	(86.1		)	(145.2		)
Cash and cash equivalents:
Net change	89.4			26.0
Balance at beginning of period	32.4			17.0
Cash and cash equivalents at end of period	$	121.8		$	43.0
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	61.1		$	77.3
Income taxes paid / (refunded), net	$	0.3		$	0.8
Non-cash financing and investing activities:
Accruals for capital expenditures	$	15.9		$	12.6

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL Inc.

Notes to Condensed Consolidated Financial Statements (Unaudited)

Note 1 – Overview and Summary of Significant Accounting Policies

Description of Business

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’sone reportable segment is the Utility segment, comprised of its DP&L subsidiary. DPLER, which was DPL's competitive retail segment, was sold January 1, 2016. See Note 12 – Business Segments for more information relating to these reportable segments. The terms “we,” “us,” “our” and “ours” are used to refer to DPL and its subsidiaries.

DPL is an indirectly wholly-owned subsidiary of AES.

DP&L 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, distribution and transmission retail services are still regulated. DP&L has the exclusive right to provide such distribution and transmission services to approximately 518,000 customers located in West Central Ohio. Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio. DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost. 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 1,171 people as of September 30, 2016, of which 1,163 were employed by DP&L. Approximately 62% 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 amortized cost, which was adjusted to fair value at the date of the Merger for DPL. 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

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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, 2015.

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 September 30, 2016; our results of operations for the three and nine months ended September 30, 2016 and 2015 and our cash flows for the nine months ended September 30, 2016 and 2015. 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 nine months ended September 30, 2016 may not be indicative of our results that will be realized for the full year ending December 31, 2016.

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.

As a result of push down accounting, DPL’s Condensed Consolidated Statements of Operations subsequent to the Merger include depreciation of fixed assets based upon their fair value at the Merger date.

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 September 30, 2016 and 2015 were $14.4 million and $13.0 million, respectively. The amounts of such taxes collected for the nine months ended September 30, 2016 and 2015 were $38.9 million and $38.5 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
2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective.	January 1, 2016	Deferred financing costs related to lines-of-credit of approximately $3.1 million recorded within Other deferred assets were not reclassified.
2015-03, Interest - Imputation of Interest (Subtopic 835-30)	The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective.	January 1, 2016	Deferred financing costs of approximately $2.1 million previously classified within Other prepayments and current assets and $14.0 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities.

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Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective.	January 1, 2016	There were no changes to the consolidation conclusions.
New Accounting Standards Issued But Not Yet Effective
2016-17, Consolidation (Topic 810): Interest Held through Related Parties That Are under Common Control	This standard amends the evaluation of whether a reporting entity is the primary beneficiary of a VIE by amending how a reporting entity, that is a single decision maker of a VIE, treats indirect interests in that entity held through related parties that are under common control. Transition method: retrospectively.	January 1, 2017 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 method.	January 1, 2018 Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective method	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements, but do not anticipate a material impact.
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.
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: Various.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt Instruments	This standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.
2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships	The standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.

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Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
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.
2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	The standard significantly revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. Also, it amends certain disclosure requirements associated with the fair value of financial instruments. Transition: cumulative effect in Retained Earnings as of adoption or prospectively for equity investments without readily determinable fair value.	January 1, 2018. Limited early adoption permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.
2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	The standard replaces the current lower of cost or market test with a lower of cost or net realizable value test. Transition method: prospectively.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2014-09, 2016-08, 2016-10, 2016-12 Revenue from Contracts with Customers (Topic 606)	The Revenue from Contracts with Customers standard provides a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing revenue recognition. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments to the standard provide further clarification on contract revenue recognition specifically related to the implementation of the principal versus agent evaluation, the identification of performance obligations, clarification on accounting for licenses of intellectual property, and allows for the election to account for shipping and handling activities performed after control of a good has been transferred to the customer as a fulfillment cost. Transition method: a full retrospective or modified retrospective approach.	January 1, 2018 (deferred by ASU No. 2015-14). Earlier application is permitted only as of January 1, 2017.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.

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Note 2 – Supplemental Financial Information

Accounts receivable and Inventories are as follows at September 30, 2016 and December 31, 2015:

	September 30,			December 31,
$ in millions	2016			2015
Accounts receivable, net:
Unbilled revenue	$	29.4		$	43.3
Customer receivables	81.6			56.4
Amounts due from partners in jointly owned plants	12.8			16.0
Other	12.3			6.0
Provision for uncollectible accounts	(1.2		)	(0.8		)
Total accounts receivable, net	$	134.9		$	120.9
Inventories, at average cost:
Fuel and limestone	$	42.0		$	72.2
Plant materials and supplies	36.1			34.9
Other	1.9			2.0
Total inventories, at average cost	$	80.0		$	109.1

Accounts receivable of $31.0 million as of December 31, 2015 have been excluded from the above table as they have been reclassified as "Assets held for sale". See Note 13 – Discontinued Operations.

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and nine months ended September 30, 2016 and 2015 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statements of Operations	Three months ended						Nine months ended
		September 30,						September 30,
$ in millions		2016			2015			2016			2015
Gains and losses on cash flow hedges (Note 5):
	Interest expense	$	(0.2	)	$	(0.2	)	$	(0.7	)	$	(0.7	)
	Revenue	(9.3		)	(3.8		)	(46.6		)	(7.0		)
	Purchased power	1.0			0.9			9.1			2.7
	Total before income taxes	(8.5		)	(3.1		)	(38.2		)	(5.0		)
	Tax expense	3.0			1.1			13.8			1.6
	Net of income taxes	(5.5		)	(2.0		)	(24.4		)	(3.4		)
Amortization of defined benefit pension items (Note 8):
	Operation and maintenance	—			0.1			0.2			0.3
	Tax benefit	—			—			(0.1		)	(0.4		)
	Net of income taxes	—			0.1			0.1			(0.1		)
Total reclassifications for the period, net of income taxes		$	(5.5	)	$	(1.9	)	$	(24.3	)	$	(3.5	)

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The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months endedSeptember 30, 2016 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities		Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total
Balance January 1, 2016	$	0.4	$	26.7		$	(9.7	)	$	17.4
Other comprehensive income before reclassifications	0.2		22.4			—			22.6
Amounts reclassified from accumulated other comprehensive income / (loss)	—		(24.4		)	0.1			(24.3		)
Net current period other comprehensive income / (loss)	0.2		(2.0		)	0.1			(1.7		)
Balance September 30, 2016	$	0.6	$	24.7		$	(9.6	)	$	15.7

Note 3 – Regulatory Matters

Ohio law requires that all Ohio distribution utilities file either an ESP or MRO to establish rates for SSO service. Although it has been in effect since January 2014, on June 20, 2016, the Supreme Court of Ohio (Court) issued an opinion in the appeal of DP&L’s ESP 2, which had been approved by the PUCO for the years 2014-2016 and which, among other matters, permitted DP&L to collect a non-bypassable service stability rider equal to approximately $9.2 million per month for each of those years and required DP&L to legally separate its generation assets by January 1, 2017. Over the period of ESP 2, DP&L has used all available cash flow to fund, among other things, debt repayments and necessary investments to ensure reliability and system performance. No dividends have been paid by DPL to AES during this period. In the opinion, the Court stated briefly, without expanding upon the basis, that the PUCO’s approval of the ESP was reversed on the authority of one of the Court’s prior rulings in a separate case not involving DP&L. In view of that reversal, on July 27, 2016 DP&L filed a motion to withdraw ESP 2 and implement rates consistent with those in effect as a result of ESP 1.

On August 26, 2016, the PUCO granted DP&L's motion to withdraw ESP 2, thereby terminating ESP 2 and its provisions, terms and conditions, including the requirement for DP&L to legally separate its generation assets by January 1, 2017. While DP&L may legally separate its generation assets, it is continuing to evaluate its options and timing with respect to separation. Further, the PUCO granted DP&L's motion to implement the provisions, terms and conditions of ESP 1 until a subsequent standard service offer is authorized by the PUCO. Tariffs consistent with the PUCO's Finding and Order were filed and became effective September 1, 2016. The rates under ESP 1 will be in place until rates consistent with the outcome for DP&L’s pending ESP 3 filing are approved and effective. The impact of reverting to ESP 1 is expected to result in a revenue reduction of approximately $3.0 million per month compared to those collected under ESP 2.

On February 22, 2016, DP&L filed ESP 3 at the PUCO seeking an effective date of January 1, 2017. On September 23, 2016, DP&L withdrew part of its ESP 3 filing that requested a Reliable Electricity Rider (RER). On October 11, 2016, DP&L filed an amended application requesting to recover $145.0 million per year for seven years that supports the alternative to the RER, named the Distribution Modernization Rider. Also as part of its plan, DP&L recommends including renewable energy attributes as part of the product that is competitively bid, and seeks recovery of approximately $10.5 million of regulatory assets. The plan also proposes a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan establishes new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental costs DP&L may incur. An evidentiary hearing is scheduled to begin December 5, 2016. There can be no assurance that ESP 3 will be approved as filed or on a timely basis. If ESP 3 is not approved on a timely basis or if the final ESP 3 provides for terms that are more adverse than those submitted in DP&L's application, our results of operations, financial condition and cash flows could be materially impacted.

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Note 4 – 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 September 30, 2016 and December 31, 2015. Information about the fair value of our derivative instruments can be found in Note 5 – Derivative Instruments and Hedging Activities.

	September 30, 2016				December 31, 2015
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.3	$	0.3	$	0.2	$	0.2
Equity securities	2.4		3.4		3.0		3.8
Debt securities	4.5		4.5		4.4		4.3
Hedge funds	0.2		0.2		0.4		0.4
Real estate	0.3		0.3		0.3		0.3
Total Assets	$	7.7	$	8.7	$	8.3	$	9.0
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Debt	$	1,914.0	$	1,969.4	$	1,993.3	$	1,975.3

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 Debt, which is presented at amortized carrying value.

Debt

Unrealized gains or losses are not recognized in the financial statements as debt is presented at cost, net of unamortized premium or discount and deferred financing costs in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2016 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 $0.9 million ($0.6 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2016 and $0.7 million ($0.5 million after tax) of unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at December 31, 2015.

During the nine months endedSeptember 30, 2016, $2.3 million ($1.5 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);

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• 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 and Level 2 of the fair value hierarchy during the nine months ended September 30, 2016 and 2015.

The fair value of assets and liabilities at September 30, 2016 and December 31, 2015 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 September 30, 2016		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	—	$	—
Equity securities	3.4		—		3.4		—
Debt securities	4.5		—		4.5		—
Hedge funds	0.2		—		0.2		—
Real estate	0.3		—		0.3		—
Total Master Trust assets	8.7		0.3		8.4		—
Derivative Assets
FTRs	0.1		—		—		0.1
Forward power contracts	33.1		—		32.5		0.6
Total Derivative assets	33.2		—		32.5		0.7
Total Assets	$	41.9	$	0.3	$	40.9	$	0.7
Liabilities
Derivative Liabilities
Forward power contracts	30.9		—		25.9		5.0
Total Derivative liabilities	30.9		—		25.9		5.0
Debt	1,969.4		—		1,951.4		18.0
Total Liabilities	$	2,000.3	$	—	$	1,977.3	$	23.0

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Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at December 31, 2015		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.2	$	0.2	$	—	$	—
Equity securities	3.8		—		3.8		—
Debt securities	4.3		—		4.3		—
Hedge funds	0.4		—		0.4		—
Real estate	0.3		—		0.3		—
Total Master Trust assets	9.0		0.2		8.8		—
Derivative assets
Forward power contracts	30.5		—		30.5		—
FTRs	0.2		—		—		0.2
Total Derivative assets	30.7		—		30.5		0.2
Total Assets	$	39.7	$	0.2	$	39.3	$	0.2
Liabilities
Derivative liabilities
FTRs	$	0.5	$	—	$	—	0.5
Forward power contracts	27.0		—		23.9		3.1
Total Derivative liabilities	27.5		—		23.9		3.6
Debt	1,975.3		—		1,957.2		18.1
Total Liabilities	$	2,002.8	$	—	$	1,981.1	$	21.7

Our financial instruments are valued using the market approach in the following categories:

• Level 1 inputs are used for derivative contracts such as heating oil futures, 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 93% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Our 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 debt is not recorded at fair value.

Cash Equivalents

DPL had $90.1 million in money market funds included as part of cash and cash equivalents in its Consolidated Balance Sheet at September 30, 2016. The money market funds have quoted prices that are generally equivalent to par.

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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. AROs for ash ponds, asbestos, river structures and underground storage tanks increased by a net amount of $3.0 million and increased by a net amount of $38.7 million during the nine months ended September 30, 2016 and 2015, respectively.

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 nine months endedSeptember 30, 2016 and their level within the fair value hierarchy (there were no impairments during the nine months ended September 30, 2015):

$ in millions	Nine months ended September 30, 2016
	Carrying		Fair Value						Gross
	Amount (b)		Level 1		Level 2		Level 3		Loss
Assets
Long-lived assets (a)
DP&L (Killen)	$	315.1	$	—	$	—	$	84.3	$	230.8
DP&L (peaking facilities)	$	9.9	$	—	$	—	$	5.2	$	4.7

(a)See Note 14 – Fixed-asset Impairment 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 nine months ended September 30, 2016:

$ in millions	Fair value		Valuation technique	Unobservable input	Range (weighted average)
Long-lived assets held and used:
DP&L (Killen)	$	84.3	Discounted cash flow	Annual revenue growth	-11% to 13% (2%)
				Annual pre-tax operating margin	-50% to 57% (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 5 – 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.

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At September 30, 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	2.8	—		2.8
Natural Gas Futures	Not designated	Dths	—	(20.0	)	(20.0	)
Forward power contracts	Designated	MWh	607.6	(10,699.9	)	(10,092.3	)
Forward power contracts	Not designated	MWh	2,866.9	(2,393.1	)	473.8

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

At December 31, 2015, 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	10.2	—		10.2
Forward power contracts	Designated	MWh	1,676.7	(7,795.8	)	(6,119.1	)
Forward power contracts	Not designated	MWh	5,049.9	(1,663.0	)	3,386.9

(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.

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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 nine months endedSeptember 30, 2016 and 2015:

	Three months ended						Three months ended
	September 30, 2016						September 30, 2015
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	3.4		$	17.3		$	1.1		$	17.8
Net gains associated with current period hedging transactions	9.5			—			7.8			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.1		)	—			(0.1		)
Revenues	(6.0		)	—			(2.5		)	—
Purchased power	0.6			—			0.6			—
Ending accumulated derivative gains in AOCI	$	7.5		$	17.2		$	7.0		$	17.7
	Nine months ended						Nine months ended
	September 30, 2016						September 30, 2015
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	9.2		$	17.5		$	0.2		$	18.3
Net gains associated with current period hedging transactions	22.4			—			9.6			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.3		)	—			(0.6		)
Revenues	(30.0		)	—			(4.5		)	—
Purchased power	5.9			—			1.7			—
Ending accumulated derivative gains in AOCI	$	7.5		$	17.2		$	7.0		$	17.7
Portion expected to be reclassified to earnings in the next twelve months (a)	$	—		$	0.6
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	15			0

(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 sales 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, heating oil futures, natural gas, and certain forward power contracts are currently marked to market.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting and are recognized in the Condensed Consolidated Statements of Operations on an accrual basis.

Regulatory Assets and Liabilities

In accordance with regulatory accounting under GAAP, a cost or loss that is probable of recovery in future rates should be deferred as a regulatory asset and revenue or a gain that is probable of being returned to customers should be deferred as a regulatory liability. Therefore, a portion of the heating oil futures are assigned to the retail

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jurisdiction and deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made. Beginning January 1, 2016, we no longer assign any portion of the heating oil futures to our retail jurisdiction as all of our SSO retail sales are sourced through the competitive bid process.

Financial Statement Effect

The following tables present the amount and classification within the Condensed Consolidated Statements of Operations or Condensed Consolidated Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and nine months ended September 30, 2016 and 2015:

For the three months ended September 30, 2016
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	—		$	1.2		$	(0.3	)	$	0.9
Realized gain / (loss)	(0.1		)	(2.4		)	0.2			(2.3		)
Total	$	(0.1	)	$	(1.2	)	$	(0.1	)	$	(1.4	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(10.4	)	$	—		$	(10.4	)
Purchased power	(0.1		)	9.2			(0.1		)	9.0
Total	$	(0.1	)	$	(1.2	)	$	(0.1	)	$	(1.4	)

For the three months ended September 30, 2015
$ in millions	Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	0.1		$	0.1		$	(3.2	)	$	(3.0	)
Realized loss	(0.2		)	(0.1		)	(4.3		)	(4.6		)
Total	$	(0.1	)	$	—		$	(7.5	)	$	(7.6	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	—		$	3.5		$	3.5
Purchased power	—			—			(11.0		)	(11.0		)
Fuel	(0.1		)	—			—			$	(0.1	)
Total	$	(0.1	)	$	—		$	(7.5	)	$	(7.6	)

For the nine months ended September 30, 2016
$ in millions	FTRs			Power			Natural Gas		Total
Change in unrealized gain	$	0.4		$	2.3		$	—	$	2.7
Realized gain / (loss)	(0.4		)	(5.3		)	0.7		(5.0		)
Total	$	—		$	(3.0	)	$	0.7	$	(2.3	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(13.1	)	$	—	$	(13.1	)
Purchased power	—			10.1			0.7		10.8
Total	$	—		$	(3.0	)	$	0.7	$	(2.3	)

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For the nine months ended September 30, 2015
$ in millions	Heating Oil			FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	0.4		$	0.2		$	(4.9	)	$	0.1		$	(4.2	)
Realized loss	(0.3		)	(0.1		)	(8.1		)	(0.1		)	(8.6		)
Total	$	0.1		$	0.1		$	(13.0	)	$	—		$	(12.8	)
Recorded on Balance Sheet: gain
Regulatory asset	$	0.1		$	—		$	—		$	—		$	0.1
Recorded in Income Statement: gain / (loss)
Revenue	—			—			8.9			—			8.9
Purchased power	—			0.1			(21.9		)	—			(21.8		)
Total	$	0.1		$	0.1		$	(13.0	)	$	—		$	(12.8	)

DPL has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements.

The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged. The following table presents the fair value and balance sheet classification of DPL’s derivative instruments at September 30, 2016:

Fair Values of Derivative Instruments
at September 30, 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	$	15.6	$	(13.3	)	$	—		$	2.3
Forward power contracts	Not designated	8.7		(7.6		)	—			1.1
FTRs	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	7.4		(1.1		)	—			6.3
Forward power contracts	Not designated	1.4		(0.7		)	—			0.7
Total assets		$	33.2	$	(22.7	)	$	—		$	10.5
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	16.1	$	(13.3	)	$	(2.7	)	$	0.1
Forward power contracts	Not designated	12.8		(7.6		)	(2.4		)	2.8
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	1.1		(1.1		)	—			—
Forward power contracts	Not designated	0.9		(0.7		)	—			0.2
Total liabilities		$	30.9	$	(22.7	)	$	(5.1	)	$	3.1

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The following table presents the fair value and balance sheet classification of DPL’s derivative instruments at December 31, 2015:

Fair Values of Derivative Instruments
at December 31, 2015
				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	$	16.2	$	(7.1	)	$	—		$	9.1
Forward power contracts	Not designated	7.3		(5.5		)	—			1.8
FTRs	Not designated	0.2		(0.2		)	—			—
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	3.0		(2.4		)	—			0.6
Forward power contracts	Not designated	4.0		(2.7		)	—			1.3
Total assets		$	30.7	$	(17.9	)	$	—		$	12.8
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	7.1	$	(7.1	)	$	—		$	—
Forward power contracts	Not designated	14.5		(5.5		)	(8.0		)	1.0
FTRs	Not designated	0.5		(0.2		)	—			0.3
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	2.7		(2.4		)	—			0.3
Forward power contracts	Not designated	2.7		(2.7		)	—			—
Total liabilities		$	27.5	$	(17.9	)	$	(8.0	)	$	1.6

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 that threshold with one counterparty to the derivative instruments and they could request that we post collateral of $0.9 million at this time.

The aggregate fair value of DPL’s commodity derivative instruments that were in a MTM loss position at September 30, 2016 was $30.9 million. $5.1 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 $22.7 million. Since our debt is below investment grade, we could have to post collateral for the remaining $3.1 million.

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Note 6 – Debt

The following table provides a summary of DPL's outstanding debt.

	Interest		September 30,			December 31,
$ in millions	Rate	Maturity	2016			2015
Term loan - rate at 4.00% (a)		2022	$	445.0		$	—
First mortgage bonds	1.875%	2016	—			445.0
Pollution control series	4.8%	2036	100.0			100.0
Pollution control series - rates from 1.29% - 1.36% (a) and 1.13% - 1.17% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	18.0			18.1
Unamortized deferred financing costs			(5.6		)	(5.0		)
Unamortized debt discount and premiums, net			(11.1		)	(3.6		)
Total long-term debt at subsidiary			746.3			754.5
Bank term loan - rates from 2.67% - 2.77% (a) and 2.44% - 2.67% (b)		2020	125.0			125.0
Senior unsecured bonds	6.5%	2016	57.0			130.0
Senior unsecured bonds	6.75%	2019	200.0			200.0
Senior unsecured bonds	7.25%	2021	780.0			780.0
Note to DPL Capital Trust II (c)	8.125%	2031	15.6			15.6
Unamortized deferred financing costs			(9.3		)	(11.1		)
Unamortized debt discounts and premiums, net			(0.6		)	(0.7		)
Total long-term debt			1,914.0			1,993.3
Less: current portion			(79.2		)	(572.8		)
Total long-term debt			$	1,834.8		$	1,420.5

(a) Range of interest rates for the nine months endedSeptember 30, 2016.

(b) Range of interest rates for the year ended December 31, 2015.

(c) Note payable to related party. See Note 11 – Related Party Transactions for additional information.

Premiums or discounts recognized at the date of the Merger are amortized over the remaining life of the debt using the effective interest method.

Significant transactions

On February 5, 2016, $73.0 million of DPL's$130.0 million6.5% Senior Unsecured Notes Due 2016 were redeemed under the indenture's make-whole call provision, which allows for the bonds to be called prior to maturity with a make-whole payment as determined by discounting the bond's future cash flow by a similarly maturing U.S. Treasury bond's yield plus 50 basis points. On the call date, principal plus the make-whole payment due totaled $75.4 million, which was paid with cash on hand. On October 17, 2016, the remaining $57.0 million of the 6.5% Senior Unsecured Notes Due 2016 were redeemed at maturity with cash on hand.

On August 24, 2016, DP&L refinanced its $445.0 million of 1.875% First Mortgage Bonds due 2016, with a variable rate Term Loan B of $445.0 million maturing on August 24, 2022 and secured by a pledge of DP&L First Mortgage Bonds. The variable interest rate on the loan is calculated based on LIBOR plus a spread of 3.25%, with a LIBOR floor of 0.75%. Up to the maturity date but not starting until March 31, 2017, the loan amortizes 0.25% of the initial principal balance quarterly, and contains covenants and restrictions that are generally consistent with existing DP&L credit agreements.

Debt covenants and restrictions

DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement have two financial covenants. The first financial covenant measures Total Debt to Total Capitalization. The Total Debt to Total Capitalization ratio 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. The 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.

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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.

Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage.

Note 7 – Income Taxes

The following table details the effective tax rates for the three and nine months ended September 30, 2016 and 2015.

	Three months ended		Nine months ended
	September 30,		September 30,
	2016	2015	2016	2015
DPL	45.7%	(34.1)%	38.6%	24.6%

Income tax expense for the nine months endedSeptember 30, 2016 and 2015 was calculated using the estimated annual effective income tax rates for 2016 and 2015 of 38.6% and 30.8%, respectively. For the three and nine months ended September 30, 2016 and 2015, management estimated 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.

For the three months ended September 30, 2016, DPL’s current period effective tax rate was greater than the estimated annual effective rate primarily due to a change in its uncertain tax positions. The increase in the annual effective rate compared to the same period in 2015 is primarily due to a forecasted pre-tax loss in the 2016 tax year.

Note 8 – 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 made during the nine months endedSeptember 30, 2016 and $5.0 million in employer contributions during the nine months endedSeptember 30, 2015.

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 amounts presented for postretirement include both health and life insurance. The pension and postretirement 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. See Note 11 – Related Party Transactions.

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The net periodic benefit cost of the pension and postretirement benefit plans for the three and nine months ended September 30, 2016 and 2015 was:

Net Periodic Benefit Cost	Pension
	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
Service cost	$	1.4		$	1.7		$	4.2		$	5.3
Interest cost	3.7			4.4			11.1			13.0
Expected return on plan assets	(5.7		)	(5.7		)	(17.1		)	(17.0		)
Amortization of unrecognized:
Prior service cost	0.4			0.5			1.4			1.5
Actuarial loss	1.1			1.5			3.2			4.4
Net periodic benefit cost	$	0.9		$	2.4		$	2.8		$	7.2

Net Periodic Benefit Cost	Postretirement
	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
Service cost	$	—		$	0.1		$	0.1		$	0.1
Interest cost	0.2			0.2			0.4			0.5
Expected return on plan assets	(0.1		)	(0.1		)	(0.1		)	(0.1		)
Amortization of unrecognized:
Prior service cost	—			—			—			—
Actuarial gain	(0.1		)	(0.1		)	(0.4		)	(0.3		)
Net periodic benefit cost	$	—		$	0.1		$	—		$	0.2

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:

$ in millions	Pension		Postretirement
2016	$	6.2	$	0.4
2017	25.2		1.6
2018	25.8		1.5
2019	26.3		1.4
2020	26.7		1.4
2021 - 2025	134.8		5.7

Note 9 - Redeemable Preferred Stock of Subsidiary

On October 13, 2016 (the "Redemption Date"), DPL's subsidiary, DP&L, redeemed all of its issued and outstanding preferred stock, consisting of the following series: Preferred Stock, 3.75% Series A, Cumulative (the “Series A Stock”); Preferred Stock, 3.75% Series B, Cumulative (the “Series B Stock”); and Preferred Stock, 3.90% Series C, Cumulative (the “Series C Stock” and, together with the Series A Stock and the Series B Stock, the “Preferred Stock”). On the Redemption Date, the Preferred Stock of each series was redeemed at the following prices as specified in DP&L’s Amended and Restated Articles of Incorporation,plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date: a price of $102.50 per share for the Series A Stock, a price of $103.00 per share for the Series B Stock, and a price of $101.00 per share for the Series C Stock. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock is no longer outstanding, andall rights of the holders thereof as shareholders of DP&L, except the right to payment of the redemption price, ceased to exist.

As we issued the notice to redeem the preferred stock of DP&L in the third quarter, the $23.5 million redemption value was included in Other Current Liabilities as of September 30, 2016. The difference between the carrying value of the Redeemable Preferred Stock of Subsidiary and the redemption amount was charged to Other paid-in capital.

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In addition, with DP&L preferred stock no longer outstanding, certain provisions in DP&L's Amended Articles of Incorporation which could limit the payment of cash dividends on any of its common stock, no longer apply.

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 these subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes.

At September 30, 2016, DPL had $16.6 million of guarantees on behalf of AES Ohio Generation to third parties for future financial or performance assurance under such agreements. The guarantee arrangements entered into by DPL with these third parties cover 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 $4.8 million and $0.5 million at September 30, 2016 and December 31, 2015, 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 owns a 4.9% equity ownership interest in OVEC, which is recorded using the cost method of accounting under GAAP. As of September 30, 2016, DP&L could be responsible for the repayment of 4.9%, or $74.9 million, of a $1,528.0 million debt obligation that has maturities from 2018 to 2040. This would only happen if OVEC defaulted on its debt payments. As of September 30, 2016, 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, 2015.

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 September 30, 2016, 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 and the Ohio EPA that require or will require substantial reductions in SO₂, particulates, mercury, acid gases, NOx, and other air emissions. DP&L has installed

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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 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 – Related Party Transactions

Service Company

Effective January 1, 2014, the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L. The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of other businesses.

Benefit plans

DPL has an agreement with AES or one of its affiliates to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. AES or its affiliate administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments.

The following table provides a summary of these transactions:

	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2016		2015		2016			2015
Transactions with the Service Company
Charges for services provided	$	9.7	$	8.9	$	32.8		$	28.5
Charges to the Service Company	$	1.1	$	1.1	$	3.4		$	5.1
Transactions with other AES affiliates:
Charges for health, welfare and benefit plans	$	3.9	$	4.3	$	5.6		$	12.5
Transactions with the Service Company:					At September 30, 2016			At December 31, 2015
Net payable to the Service Company					$	(1.4	)	$	(0.5	)

DPL Capital Trust II

DPL has a wholly-owned business trust, DPL Capital Trust II (the "Trust"), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.3 million and $0.3 million at September 30, 2016 and December 31, 2015, respectively, is included in Other deferred assets within Other non-current assets. DPL also has a note payable to the Trust amounting to $15.6 million and $15.6 million at September 30, 2016 and December 31, 2015, respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 6 – Debt for additional information.

In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust.

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Income taxes

AES files federal and state income tax returns which consolidate DPL and its subsidiaries. Under a tax sharing agreement with AES, DPL is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. DPL had net payable balances of $97.0 million and $50.5 million at September 30, 2016 and December 31, 2015, respectively, which are recorded in Accounts receivable, net and Accrued taxes on the accompanying Balance Sheets on a gross basis.

Note 12 – Business Segments

At December 31, 2015, DPL had two segments consisting of the operations of two of its wholly-owned subsidiaries, DP&L (Utility segment)and DPLER (Competitive Retail segment which included DPLER's wholly-owned subsidiary, MC Squared). This is how we viewed our business and made decisions on how to allocate resources and evaluate performance.

The Competitive Retail segment, DPLER’s competitive retail electric service business, was sold on January 1, 2016 (see Note 13 – Discontinued Operations). DPL now operates through one segment, the Utility segment. Segment disclosures for 2015 have not been restated to show the competitive retail segment as a discontinued operation and therefore do not tie to the Condensed Consolidated Statement of Operations.

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and deliver electricity to residential, commercial, industrial and governmental customers. DP&L generates electricity at five coal-fired power plants and DP&L distributes power to approximately 518,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. Prior to the sale of DPLER, DP&L also sold electricity to DPLER and to other Ohio utilities. In 2016, all of DP&L's electricity for SSO customers was sourced through a competitive bid auction and DP&L's energy and capacity was primarily sold into the PJM wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.

The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L. Intercompany sales from DP&L to DPLER were based on fixed-price contracts for each customer; the price approximated market prices for wholesale power at the inception of each customer’s contract. These agreements were terminated in connection with the sale of DPLER on January 1, 2016.

Included in the “Other” column in the following tables are other businesses that do not meet the GAAP requirements for disclosure as reportable segments, certain corporate costs including interest expense on DPL’s debt, and adjustments related to purchase accounting from the Merger. Management evaluates segment performance based on gross margin. 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.

34

The following tables present financial information for each of DPL’s reportable business segments:

$ in millions	Utility Segment		Other			Adjustments and Eliminations			DPL Consolidated
For the three months ended September 30, 2016
Revenues from external customers	$	368.0	$	21.3		$	—		$	389.3
Intersegment revenues	0.4		2.0			(2.4		)	—
Total revenues	368.4		23.3			(2.4		)	389.3
Fuel	71.0		7.9			—			78.9
Purchased power	110.0		3.0			(1.3		)	111.7
Gross margin	$	187.4	$	12.4		$	(1.1	)	$	198.7
Depreciation and amortization	$	24.1	$	6.8		$	—		$	30.9
Interest expense	$	6.5	$	20.3		$	0.2		$	27.0
Income tax expense / (benefit)	$	19.7	$	(7.0	)	$	—		$	12.7
Net income / (loss)	$	30.1	$	(15.0	)	$	—		$	15.1
Cash capital expenditures	$	26.5	$	4.2		$	—		$	30.7

$ in millions	Utility Segment		Competitive Retail		Other			Adjustments and Eliminations			DPL Consolidated
For the three months ended September 30, 2015
Revenues from external customers	$	323.2	$	77.0	$	13.9		$	—		$	414.1
Intersegment revenues	66.0		—		1.5			(67.5		)	—
Total revenues	389.2		77.0		15.4			(67.5		)	414.1
Fuel	69.0		—		2.4			—			71.4
Purchased power	142.5		66.6		3.0			(66.7		)	145.4
Gross margin	$	177.7	$	10.4	$	10.0		$	(0.8	)	$	197.3
Depreciation and amortization	$	34.6	$	0.2	$	—		$	—		$	34.8
Interest expense	$	6.9	$	—	$	22.1		$	(0.1	)	$	28.9
Income tax expense / (benefit)	$	0.8	$	1.6	$	(2.1	)	$	—		$	0.3
Net income / (loss)	$	15.5	$	2.6	$	(9.5	)	$	—		$	8.6
Cash capital expenditures	$	27.9	$	0.3	$	0.5		$	—		$	28.7

35

$ in millions	Utility Segment			Other			Adjustments and Eliminations			DPL Consolidated
For the nine months ended September 30, 2016
Revenues from external customers	$	1,030.3		$	51.3		$	—		$	1,081.6
Intersegment revenues	1.0			4.2			(5.2		)	—
Total revenues	1,031.3			55.5			(5.2		)	1,081.6
Fuel	189.5			16.5			—			206.0
Purchased power	328.0			4.9			(2.4		)	330.5
Gross margin	$	513.8		$	34.1		$	(2.8	)	$	545.1
Depreciation and amortization	$	95.2		$	5.1		$	—		$	100.3
Fixed-asset impairment	$	857.1		$	(621.6	)	$	—		$	235.5
Interest expense	$	17.2		$	61.6		$	0.5		$	79.3
Income tax expense / (benefit)	$	(271.6	)	$	196.6		$	—		$	(75.0	)
Net income / (loss) from continuing operations	$	(467.8	)	$	348.3		$	—		$	(119.5	)
Discontinued operations, net of tax	$	—		$	29.6		$	—		$	29.6
Net income / (loss)	$	(467.8	)	$	377.9		$	—		$	(89.9	)
Cash capital expenditures	$	98.3		$	11.5		$	—		$	109.8
at September 30, 2016
Total assets	$	2,460.8		$	1,303.8		$	(814.2	)	$	2,950.4

$ in millions	Utility Segment		Competitive Retail			Other			Adjustments and Eliminations			DPL Consolidated
For the nine months ended September 30, 2015
Revenues from external customers	$	957.6	$	274.5		$	49.4		$	—		$	1,281.5
Intersegment revenues	245.0		—			4.4			(249.4		)	—
Total revenues	1,202.6		274.5			53.8			(249.4		)	1,281.5
Fuel	188.9		—			13.3			—			202.2
Purchased power	452.3		247.0			7.8			(246.9		)	460.2
Gross margin	$	561.4	$	27.5		$	32.7		$	(2.5	)	$	619.1
Depreciation and amortization	$	103.5	$	0.6		$	—		$	—		$	104.1
Interest expense	$	24.6	$	0.1		$	65.8		$	(0.2	)	$	90.3
Income tax expense / (benefit)	$	25.0	$	(2.6	)	$	(8.9	)	$	—		$	13.5
Net income / (loss)	$	75.9	$	10.9		$	(27.8	)	$	—		$	59.0
Cash capital expenditures	$	91.2	$	0.6		$	1.7		$	—		$	93.5
at December 31, 2015
Total assets	$	3,359.6	$	—		$	1,304.5		$	(1,339.4	)	$	3,324.7

Note 13 – 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 received $75.5 million of restricted cash on December 31, 2015 for the sale. This amount was shown as Restricted cash with the associated liability shown as "Deposit received on sale of DPLER" on the Balance Sheet as of December 31, 2015. Assets and liabilities related to DPLER were reclassified

36

to "Assets held for sale" and "Liabilities held for sale" in the December 31, 2015 Condensed Consolidated Balance Sheet. 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 at December 31, 2015. Deferred taxes and intercompany balances were not reclassified to held for sale.

Operating activities related to DPLER have been reclassified to "Discontinued operations" in the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2015.

The following table summarizes the major categories of assets, liabilities at the dates indicated, and the revenues, cost of revenues, operating expenses and income tax of discontinued operations as of and for the periods indicated:

$ in millions									December 31, 2015
Accounts receivable, net									$	31.0
Property, plant & equipment, net									4.6
Intangible assets, net									24.6
Other assets									2.0
Total assets of the disposal group classified as held for sale in the balance sheets									$	62.2
Accounts payable									$	0.8
Other liabilities									0.8
Total liabilities of the disposal group classified as held for sale in the balance sheets									$	1.6
	Three months ended September 30,					Nine months ended September 30,
	2016		2015			2016			2015
Revenues	$	—	$	77.1		$	—		$	274.6
Cost of revenues	—		(66.5		)	—			(247.0		)
Operating expenses	—		(5.7		)	(0.7		)	(17.5		)
(Loss) / income from discontinued operations before income taxes	—		4.9			(0.7		)	10.1
Gain from disposal of discontinued operations	—		—			49.2			—
Income tax expense / (benefit)	—		1.8			18.9			(1.8		)
Income on discontinued operations	$	—	$	3.1		$	29.6		$	11.9

DPLER purchased its power from DP&L during 2015. Prior to DPLER being presented as a discontinued operation, this purchased power and DP&L's corresponding wholesale revenue would have been eliminated in consolidation.

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 and $28.4 million for the nine months endedSeptember 30, 2016 and 2015, respectively. Cash flows from investing activities for discontinued operations were $75.5 million and $0.7 million for the nine months endedSeptember 30, 2016 and 2015, respectively. All cash generated from discontinued operations was paid to DPL through dividends for all periods presented.

Note 14 – Fixed-asset Impairment

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

37

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 an 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

39

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF OPERATIONS
	Three months ended September 30,						Nine months ended September 30,
$ in millions	2016			2015			2016			2015
Revenues	$	368.4		$	389.2		$	1,031.3		$	1,202.6
Cost of revenues:
Fuel	71.0			69.0			189.5			188.9
Purchased power	110.0			142.5			328.0			452.3
Total cost of revenues	181.0			211.5			517.5			641.2
Gross margin	187.4			177.7			513.8			561.4
Operating expenses:
Operation and maintenance	85.5			93.5			248.0			261.6
Depreciation and amortization	24.1			34.6			95.2			103.5
General taxes	21.2			21.1			62.8			65.0
Gain on termination of contract	—			—			(27.7		)	—
Fixed-asset impairment	—			—			857.1			—
Other	—			—			0.2			0.4
Total operating expenses	130.8			149.2			1,235.6			430.5
Operating income / (loss)	56.6			28.5			(721.8		)	130.9
Other income / (expense), net:
Investment income	0.1			—			0.3			0.2
Interest expense	(6.5		)	(6.9		)	(17.2		)	(24.6		)
Charge for early retirement of debt	(0.5		)	(5.0		)	(0.5		)	(5.0		)
Other income / (expense), net:	0.1			(0.3		)	(0.2		)	(0.6		)
Total other expense, net	(6.8		)	(12.2		)	(17.6		)	(30.0		)
Earnings / (loss) before income taxes	49.8			16.3			(739.4		)	100.9
Income tax expense / (benefit)	19.7			0.8			(271.6		)	25.0
Net income / (loss)	30.1			15.5			(467.8		)	75.9
Dividends on preferred stock	0.3			0.3			0.7			0.7
Income / (loss) attributable to common stock	$	29.8		$	15.2		$	(468.5	)	$	75.2

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

40

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
	Three months ended September 30,						Nine months ended September 30,
$ in millions	2016			2015			2016			2015
Net income / (loss)	$	30.1		$	15.5		$	(467.8	)	$	75.9
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax (expense) / benefit of $0.0, $0.1, $(0.1) and $0.1 for each respective period	0.1			(0.3		)	0.2			(0.3		)
Reclassification to earnings, net of income tax expense of $0.0, $0.0, $0.0 and $0.0 for each respective period	—			—			—			—
Total change in fair value of available-for-sale securities	0.1			(0.3		)	0.2			(0.3		)
Derivative activity:
Change in derivative fair value, net of income tax (expense) / benefit of $5.2, $(4.4), $(12.2) and $(5.4) for each respective period	9.5			7.8			22.5			9.6
Reclassification to earnings, net of income tax benefit of $3.0, $1.2, $13.5 and $1.9 for each respective period	(5.6		)	(2.0		)	(24.8		)	(3.3		)
Total change in fair value of derivatives	3.9			5.8			(2.3		)	6.3
Pension and postretirement activity:
Reclassification to earnings, net of income tax expense of $(0.4), $(0.6), $(1.6) and $(1.6) for each respective period	0.7			0.8			1.7			2.6
Total change in unfunded pension obligation	0.7			0.8			1.7			2.6
Other comprehensive income / (loss)	4.7			6.3			(0.4		)	8.6
Net comprehensive income / (loss)	$	34.8		$	21.8		$	(468.2	)	$	84.5

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

41

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS
	September 30,			December 31,
$ in millions	2016			2015
ASSETS
Current assets:
Cash and cash equivalents	$	92.9		$	5.4
Restricted cash	11.6			44.8
Accounts receivable, net (Note 2)	136.3			119.5
Inventories (Note 2)	78.6			108.0
Taxes applicable to subsequent years	19.2			79.2
Regulatory assets, current	—			14.4
Other prepayments and current assets	36.7			46.3
Total current assets	375.3			417.6
Property, plant & equipment:
Property, plant & equipment	3,073.4			5,244.7
Less: Accumulated depreciation and amortization	(1,285.8		)	(2,584.0		)
	1,787.6			2,660.7
Construction work in process	89.9			78.0
Total net property, plant & equipment	1,877.5			2,738.7
Other non-current assets:
Regulatory assets, non-current	186.9			179.9
Intangible assets, net of amortization	0.9			5.0
Other deferred assets	20.2			18.4
Total other non-current assets	208.0			203.3
Total assets	$	2,460.8		$	3,359.6
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt (Note 6)	$	3.5		$	443.1
Short-term debt (Note 11)	—			35.0
Accounts payable	76.8			94.1
Accrued taxes	122.2			86.2
Accrued interest	1.0			4.1
Security deposits	14.6			15.1
Regulatory liabilities, current	44.7			24.4
Other current liabilities	75.6			51.0
Advance on contract termination	—			27.7
Total current liabilities	338.4			780.7
Non-current liabilities:
Long-term debt (Note 6)	745.0			313.6
Deferred taxes	314.4			631.2
Taxes payable	1.5			82.1
Regulatory liabilities, non-current	129.9			127.0
Pension, retiree and other benefits	80.5			87.1
Unamortized investment tax credit	18.3			20.0
Other deferred credits	82.1			82.3
Total non-current liabilities	1,371.7			1,343.3
Redeemable preferred stock (Note 9)	—			22.9
Commitments and contingencies (Note 10)
Common shareholder's equity:
Common stock, at par value of $0.01 per share	0.4			0.4
Other paid-in capital	810.6			803.7
Accumulated other comprehensive loss	(29.1		)	(28.7		)
Retained earnings / (Accumulated deficit)	(31.2		)	437.3
Total common shareholder's equity	750.7			1,212.7
Total liabilities and shareholder's equity	$	2,460.8		$	3,359.6

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

42

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
	Nine months ended September 30,
$ in millions	2016			2015
Cash flows from operating activities:
Net income / (loss)	$	(467.8	)	$	75.9
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Depreciation and amortization	95.2			103.5
Charge for early redemption of debt	0.5			5.0
Deferred income taxes	(314.2		)	(14.2		)
Fixed-asset impairment	857.1			—
Changes in certain assets and liabilities:
Accounts receivable	(11.0		)	37.3
Inventories	29.4			3.0
Prepaid taxes	2.7			(0.4		)
Taxes applicable to subsequent years	59.9			56.4
Deferred regulatory costs, net	19.5			27.6
Accounts payable	(13.5		)	(20.0		)
Accrued taxes payable	(43.2		)	(29.1		)
Accrued interest payable	(3.3		)	(8.8		)
Pension, retiree and other benefits	(2.2		)	1.0
Other	11.3			10.5
Net cash provided by operating activities	220.4			247.7
Cash flows from investing activities:
Capital expenditures	(98.3		)	(91.2		)
Purchase of renewable energy credits	(0.3		)	(0.6		)
Decrease in restricted cash	5.5			3.2
Insurance proceeds	5.6			4.3
Other investing activities, net	0.9			0.4
Net cash used in investing activities	(86.6		)	(83.9		)
Cash flows from financing activities:
Dividends paid on common stock to parent	—			(50.0		)
Borrowings from revolving credit facilities	—			50.0
Repayment of borrowings from revolving credit facilities	—			(40.0		)
Dividends paid on preferred stock	(0.7		)	(0.7		)
Issuance of long-term debt, net of discount	442.8			200.0
Retirement of long-term debt	(445.3		)	(314.5		)
Payments of deferred financing costs	(8.0		)	(3.3		)
Issuance of short-term debt - related party	5.0			—
Repayment of short-term debt - related party	(40.0		)	—
Other financing activities, net	(0.1		)	—
Net cash used in financing activities	(46.3		)	(158.5		)
Cash and cash equivalents:
Net change	87.5			5.3
Balance at beginning of period	5.4			5.4
Cash and cash equivalents at end of period	$	92.9		$	10.7
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	16.3		$	26.8
Income taxes paid, net	$	0.3		$	0.8
Non-cash financing and investing activities:
Accruals for capital expenditures	$	10.1		$	12.6
Equity contribution to settle liability	$	7.5		—

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

43

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, distribution and transmission retail services are still regulated. DP&L has the exclusive right to provide such distribution and transmission services to approximately 518,000 customers located in West Central Ohio. Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio. DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost. 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’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 1,163 people as of September 30, 2016. Approximately 62% 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, peaking electric generating facilities and numerous transmission facilities, all of which are included in the financial statements at amortized cost. 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, 2015.

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 September 30, 2016; our results of operations for the three and nine months ended September 30, 2016 and 2015 and our cash flows for the nine months ended September 30, 2016 and 2015. 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 nine months ended September 30, 2016 may not be indicative of our results that will be realized for the full year ending December 31, 2016.

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.

44

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 September 30, 2016 and 2015 were $14.4 million and $13.0 million, respectively. The amounts of such taxes collected for the nine months ended September 30, 2016 and 2015 were $38.9 million and $38.5 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
2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective.	January 1, 2016	Deferred financing costs related to lines-of-credit of approximately $0.7 million recorded within Other deferred assets were not reclassified.
2015-03, Interest - Imputation of Interest (Subtopic 835-30)	The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective.	January 1, 2016	Deferred financing costs of approximately $1.8 million previously classified within Other prepayments and current assets and $4.5 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities.
2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective.	January 1, 2016	There were no changes to the consolidation conclusions.
New Accounting Standards Issued But Not Yet Effective
2016-17, Consolidation (Topic 810): Interest Held through Related Parties That Are under Common Control	This standard amends the evaluation of whether a reporting entity is the primary beneficiary of a VIE by amending how a reporting entity, that is a single decision maker of a VIE, treats indirect interests in that entity held through related parties that are under common control. Transition method: retrospectively.	January 1, 2017 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 method.	January 1, 2018 Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective method	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements but do not anticipate a material impact.

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Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	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.
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: Various.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt Instruments	This standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements.
2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships	The standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact 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.
2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	The standard significantly revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. Also, it amends certain disclosure requirements associated with the fair value of financial instruments. Transition: cumulative effect in Retained Earnings as of adoption or prospectively for equity investments without readily determinable fair value.	January 1, 2018. Limited early adoption permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements.
2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	The standard replaces the current lower of cost or market test with a lower of cost or net realizable value test. Transition method: prospectively.	January 1, 2017. 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
2014-09, 2016-08, 2016-10, 2016-12 Revenue from Contracts with Customers (Topic 606)	The Revenue from Contracts with Customers standard provides a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing revenue recognition. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments to the standard provide further clarification on contract revenue recognition specifically related to the implementation of the principal versus agent evaluation, the identification of performance obligations, clarification on accounting for licenses of intellectual property, and allows for the election to account for shipping and handling activities performed after control of a good has been transferred to the customer as a fulfillment cost. Transition method: a full retrospective or modified retrospective approach.	January 1, 2018 (deferred by ASU No. 2015-14). Earlier application is permitted only as of January 1, 2017.	We are currently evaluating the impact of adopting the standard on our financial statements.

Note 2 – Supplemental Financial Information

Accounts receivable and Inventories are as follows at September 30, 2016 and December 31, 2015:

	September 30,			December 31,
$ in millions	2016			2015
Accounts receivable, net:
Unbilled revenue	$	29.4		$	43.3
Customer receivables	79.2			54.1
Amounts due from partners in jointly owned plants	12.8			16.0
Other	16.1			6.9
Provision for uncollectible accounts	(1.2		)	(0.8		)
Total accounts receivable, net	$	136.3		$	119.5
Inventories, at average cost:
Fuel and limestone	$	42.0		$	72.2
Plant materials and supplies	34.7			33.7
Other	1.9			2.1
Total inventories, at average cost	$	78.6		$	108.0

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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 nine months ended September 30, 2016 and 2015 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Statements of Operations	Three months ended						Nine months ended
		September 30,						September 30,
$ in millions		2016			2015			2016			2015
Gains and losses on cash flow hedges (Note 5):
	Interest expense	$	(0.3	)	$	(0.3	)	$	(0.9	)	$	(0.9	)
	Revenue	(9.3		)	(3.8		)	(46.5		)	(7.0		)
	Purchased power	1.0			0.9			9.1			2.7
	Total before income taxes	(8.6		)	(3.2		)	(38.3		)	(5.2		)
	Tax expense	3.0			1.2			13.5			1.9
	Net of income taxes	(5.6		)	(2.0		)	(24.8		)	(3.3		)
Amortization of defined benefit pension items (Note 8):
	Operation and maintenance	1.1			1.4			3.3			4.2
	Tax benefit	(0.4		)	(0.6		)	(1.6		)	(1.6		)
	Net of income taxes	0.7			0.8			1.7			2.6
Total reclassifications for the period, net of income taxes		$	(4.9	)	$	(1.2	)	$	(23.1	)	$	(0.7	)

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months ended September 30, 2016 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities		Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total
Balance January 1, 2016	$	0.5	$	11.2		$	(40.4	)	$	(28.7	)
Other comprehensive income before reclassifications	0.2		22.5			—			22.7
Amounts reclassified from accumulated other comprehensive income / (loss)	—		(24.8		)	1.7			(23.1		)
Net current period other comprehensive income / (loss)	0.2		(2.3		)	1.7			(0.4		)
Balance September 30, 2016	$	0.7	$	8.9		$	(38.7	)	$	(29.1	)

Note 3 – Regulatory Matters

Ohio law requires that all Ohio distribution utilities file either an ESP or MRO to establish rates for SSO service. Although it has been in effect since January 2014, on June 20, 2016, the Supreme Court of Ohio (Court) issued an opinion in the appeal of DP&L’s ESP 2, which had been approved by the PUCO for the years 2014-2016 and which, among other matters, permitted DP&L to collect a non-bypassable service stability rider equal to approximately $9.2 million per month for each of those years and required DP&L to legally separate its generation assets by January 1, 2017. Over the period of ESP 2, DP&L has used all available cash flow to fund, among other things, debt repayments and necessary investments to ensure reliability and system performance. No dividends have been paid by DPL to AES during this period. In the opinion, the Court stated briefly, without expanding upon the basis, that the PUCO’s approval of the ESP was reversed on the authority of one of the Court’s prior rulings in a separate case not involving DP&L. In view of that reversal, on July 27, 2016 DP&L filed a motion to withdraw ESP 2 and implement rates consistent with those in effect as a result of ESP 1.

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On August 26, 2016, the PUCO granted DP&L's motion to withdraw ESP 2, thereby terminating ESP 2 and its provisions, terms and conditions, including the requirement for DP&L to legally separate its generation assets by January 1, 2017. While DP&L may legally separate its generation assets, it is continuing to evaluate its options and timing with respect to separation. Further, the PUCO granted DP&L's motion to implement the provisions, terms and conditions of ESP 1 until a subsequent standard service offer is authorized by the PUCO. Tariffs consistent with the PUCO's Finding and Order were filed and became effective September 1, 2016. The rates under ESP 1 will be in place until rates consistent with the outcome for DP&L’s pending ESP 3 filing are approved and effective. The impact of reverting to ESP 1 is expected to result in a revenue reduction of approximately $3.0 million per month compared to those collected under ESP 2.

On February 22, 2016, DP&L filed ESP 3 at the PUCO seeking an effective date of January 1, 2017. On September 23, 2016, DP&L withdrew part of its ESP 3 filing that requested a Reliable Electricity Rider (RER). On October 11, 2016, DP&L filed an amended application requesting to recover $145.0 million per year for seven years that supports the alternative to the RER, named the Distribution Modernization Rider. Also as part of its plan, DP&L recommends including renewable energy attributes as part of the product that is competitively bid, and seeks recovery of approximately $10.5 million of regulatory assets. The plan also proposes a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan establishes new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental costs DP&L may incur. An evidentiary hearing is scheduled to begin December 5, 2016. There can be no assurance that ESP 3 will be approved as filed or on a timely basis. If ESP 3 is not approved on a timely basis or if the final ESP 3 provides for terms that are more adverse than those submitted in DP&L's application, our results of operations, financial condition and cash flows could be materially impacted.

Note 4 – 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 September 30, 2016 and December 31, 2015. Information about the fair value of our derivative instruments can be found in Note 5 – Derivative Instruments and Hedging Activities.

	September 30, 2016				December 31, 2015
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.3	$	0.3	$	0.2	$	0.2
Equity securities	2.4		3.4		3.0		3.8
Debt securities	4.5		4.5		4.4		4.3
Hedge funds	0.2		0.2		0.4		0.4
Real estate	0.3		0.3		0.3		0.3
Total assets	$	7.7	$	8.7	$	8.3	$	9.0
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Debt	$	748.5	$	763.5	$	756.7	$	764.2

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 Debt, which is presented at amortized carrying value.

Debt

Unrealized gains or losses are not recognized in the financial statements as debt is presented at cost, net of unamortized premium or discount and deferred financing costs in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2016 to 2061.

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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 $1.1 million ($0.7 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2016 and $0.8 million ($0.5 million after tax) in unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at December 31, 2015.

During the nine months endedSeptember 30, 2016, $2.3 million ($1.5 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 and Level 2 of the fair value hierarchy during the nine months ended September 30, 2016 and 2015.

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The fair value of assets and liabilities at September 30, 2016 and December 31, 2015 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 September 30, 2016		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	—	$	—
Equity securities	3.4		—		3.4		—
Debt securities	4.5		—		4.5		—
Hedge funds	0.2		—		0.2		—
Real estate	0.3		—		0.3		—
Total Master Trust assets	8.7		0.3		8.4		—
Derivative assets
FTRs	0.1		—		—		0.1
Forward power contracts	33.2		—		32.6		0.6
Total derivative assets	33.3		—		32.6		0.7
Total assets	$	42.0	$	0.3	$	41.0	$	0.7
Liabilities
Derivative liabilities
Forward power contracts	$	31.0	$	—	$	26.0	$	5.0
Total derivative liabilities	31.0		—		26.0		5.0
Debt	763.5		—		745.5		18.0
Total liabilities	$	794.5	$	—	$	771.5	$	23.0

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Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at December 31, 2015		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.2	$	0.2	$	—	$	—
Equity securities	3.8		—		3.8		—
Debt securities	4.3		—		4.3		—
Hedge funds	0.4		—		0.4		—
Real estate	0.3		—		0.3		—
Total Master Trust assets	9.0		0.2		8.8		—
Derivative assets
FTRs	0.2		—		—		0.2
Forward power contracts	30.6		—		30.6		—
Total Derivative assets	30.8		—		30.6		0.2
Total assets	$	39.8	$	0.2	$	39.4	$	0.2
Liabilities
Derivative liabilities
FTRs	$	0.5	$	—	$	—	$	0.5
Forward power contracts	27.0		—		23.9		3.1
Total Derivative liabilities	27.5		—		23.9		3.6
Debt	764.2		—		746.1		18.1
Total liabilities	$	791.7	$	—	$	770.0	$	21.7

Our financial instruments are valued using the market approach in the following categories:

• Level 1 inputs are used for derivative contracts such as heating oil futures, 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 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 debt is not recorded at fair value.

Approximately 93% of the inputs to the fair value of our derivative instruments are from quoted market prices.

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Cash Equivalents

DP&L had $90.1 million in money market funds included as part of cash and cash equivalents in its Balance Sheet at September 30, 2016. The money market funds have quoted prices that are generally equivalent to par.

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. AROs for ash ponds, asbestos, river structures and underground storage tanks increased by a net amount of $3.0 million and increased by a net amount of $38.7 million during the nine months ended September 30, 2016 and 2015, respectively.

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 nine months endedSeptember 30, 2016 and their level within the fair value hierarchy (there were no impairments during the nine months ended September 30, 2015):

	Carrying		Fair Value						Gross
$ in millions	Amount (b)		Level 1		Level 2		Level 3		Loss
	Nine months ended September 30, 2016
Long-lived assets (a)
DP&L (Stuart)	$	456.4	$	—	$	—	$	164.4	$	292.0
DP&L (Killen)	$	330.5	$	—	$	—	$	84.3	$	246.2
DP&L (Zimmer)	$	429.9	$	—	$	—	$	111.0	$	318.9

(a)See Note 12 – Fixed-asset Impairment 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 nine months ended September 30, 2016:

$ in millions	Fair value		Valuation technique	Unobservable input	Range (weighted average)
Long-lived assets held and used:
DP&L (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%
DP&L (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 (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 5 – 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

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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 September 30, 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	2.8	—		2.8
Natural gas futures	Not designated	Dths	—	(20.0	)	(20.0	)
Forward power contracts	Designated	MWh	607.6	(10,699.9	)	(10,092.3	)
Forward power contracts	Not designated	MWh	2,866.9	(2,419.8	)	447.1

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

At December 31, 2015, 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	10.2	—		10.2
Forward power contracts	Designated	MWh	1,676.7	(7,795.8	)	(6,119.1	)
Forward power contracts	Not designated	MWh	5,049.9	(1,665.7	)	3,384.2

(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.

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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 nine months endedSeptember 30, 2016 and 2015:

	Three months ended						Three months ended
	September 30, 2016						September 30, 2015
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	3.4		$	1.6		$	1.1		$	2.2
Net gains associated with current period hedging transactions	9.5			—			7.8			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.2		)	—			(0.1		)
Revenues	(6.0		)	—			(2.5		)	—
Purchased power	0.6			—			0.6			—
Ending accumulated derivative gains in AOCI	$	7.5		$	1.4		$	7.0		$	2.1
	Nine months ended						Nine months ended
	September 30, 2016						September 30, 2015
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	9.2		$	2.0		$	0.2		$	2.6
Net gains associated with current period hedging transactions	22.5			—			9.6			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.6		)	—			(0.5		)
Revenues	(30.1		)	—			(4.5		)	—
Purchased power	5.9			—			1.7			—
Ending accumulated derivative gains in AOCI	$	7.5		$	1.4		$	7.0		$	2.1
Portion expected to be reclassified to earnings in the next twelve months (a)	$	—		$	(0.7	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	15			0

(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 sales 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, heating oil futures, natural gas, and certain forward power contracts are currently marked to market.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting and are recognized in the Condensed Statements of Operations on an accrual basis.

Regulatory Assets and Liabilities

In accordance with regulatory accounting under GAAP, a cost or loss that is probable of recovery in future rates should be deferred as a regulatory asset and revenue or a gain that is probable of being returned to customers should be deferred as a regulatory liability. Therefore, a portion of the heating oil futures are assigned to the retail jurisdiction and deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in

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the period such determination is made. Beginning January 1, 2016, we no longer assign any portion of the heating oil futures to our retail jurisdiction as all of our SSO retail sales are sourced through the competitive bid process.

Financial Statement Effect

The following tables present the amount and classification within the Condensed Statements of Operations or Condensed Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and nine months ended September 30, 2016 and 2015:

For the three months ended September 30, 2016
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	—		$	1.2		$	(0.3	)	$	0.9
Realized gain / (loss)	(0.1		)	(2.4		)	0.2			(2.3		)
Total	$	(0.1	)	$	(1.2	)	$	(0.1	)	$	(1.4	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(10.4	)	$	—		$	(10.4	)
Purchased power	(0.1		)	9.2			(0.1		)	9.0
Total	$	(0.1	)	$	(1.2	)	$	(0.1	)	$	(1.4	)

For the three months ended September 30, 2015
$ in millions	Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	0.1		$	0.1		$	(3.3	)	$	(3.1	)
Realized loss	(0.2		)	(0.1		)	(4.3		)	(4.6		)
Total	$	(0.1	)	$	—		$	(7.6	)	$	(7.7	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	—		$	3.4		$	3.4
Purchased power	—			—			(11.0		)	(11.0		)
Fuel	(0.1		)	—			—			(0.1		)
Total	$	(0.1	)	$	—		$	(7.6	)	$	(7.7	)

For the nine months ended September 30, 2016
$ in millions	FTRs			Power			Natural Gas		Total
Change in unrealized gain	$	0.4		$	2.3		$	—	$	2.7
Realized gain / (loss)	(0.4		)	(5.3		)	0.7		(5.0		)
Total	$	—		$	(3.0	)	$	0.7	$	(2.3	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(13.1	)	$	—	$	(13.1	)
Purchased power	—			10.1			0.7		10.8
Total	$	—		$	(3.0	)	$	0.7	$	(2.3	)

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For the nine months ended September 30, 2015
$ in millions	Heating Oil			FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	0.4		$	0.2		$	(5.0	)	0.1			$	(4.3	)
Realized loss	(0.3		)	(0.1		)	(8.1		)	(0.1		)	(8.6		)
Total	$	0.1		$	0.1		$	(13.1	)	$	—		$	(12.9	)
Recorded in Balance Sheet:
Regulatory asset	$	0.1		$	—		$	—		$	—		$	0.1
Recorded in Income Statement: gain / (loss)
Purchased power	—			0.1			(21.9		)	—			(21.8		)
Fuel	—			—			8.8			—			8.8
Total	$	0.1		$	0.1		$	(13.1	)	$	—		$	(12.9	)

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. The following table presents the fair value and balance sheet classification of DP&L’s derivative instruments at September 30, 2016:

Fair Values of Derivative Instruments
at September 30, 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	$	15.6	$	(13.3	)	$	—		$	2.3
Forward power contracts	Not designated	8.8		(7.7		)	—			1.1
FTRs	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	7.4		(1.1		)	—			6.3
Forward power contracts	Not designated	1.4		(0.7		)	—			0.7
Total assets		$	33.3	$	(22.8	)	$	—		$	10.5
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	16.1	$	(13.3	)	$	(2.7	)	$	0.1
Forward power contracts	Not designated	12.9		(7.7		)	(2.4		)	2.8
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	1.1		(1.1		)	—			—
Forward power contracts	Not designated	0.9		(0.7		)	—			0.2
Total liabilities		$	31.0	$	(22.8	)	$	(5.1	)	$	3.1

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The following table presents the fair value and balance sheet classification of DP&L’s derivative instruments at December 31, 2015:

Fair Values of Derivative Instruments
at December 31, 2015
				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	$	16.2	$	(7.1	)	$	—		$	9.1
Forward power contracts	Not designated	7.4		(5.5		)	—			1.9
FTRs	Not designated	0.2		(0.2		)	—			—
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	3.0		(2.4		)	—			0.6
Forward power contracts	Not designated	4.0		(2.7		)	—			1.3
Total assets		$	30.8	$	(17.9	)	$	—		$	12.9
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	7.1	$	(7.1	)	$	—		$	—
Forward power contracts	Not designated	14.5		(5.5		)	(8.0		)	1.0
FTRs	Not designated	0.5		(0.2		)	—			0.3
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	2.7		(2.4		)	—			0.3
Forward power contracts	Not designated	2.7		(2.7		)	—			—
Total liabilities		$	27.5	$	(17.9	)	$	(8.0	)	$	1.6

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 that threshold with one counterparty to the derivative instruments and they could request that we post collateral of $0.9 million at this time.

The aggregate fair value of DP&L’s commodity derivative instruments that were in a MTM loss position at September 30, 2016 was $31.0 million. $22.8 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 $5.1 million. Since our debt is below investment grade, we could have to post collateral for the remaining $3.1 million.

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Note 6 – Debt

The following table provides a summary of DP&L's outstanding debt.

	Interest		September 30,			December 31,
$ in millions	Rate	Maturity	2016			2015
Term loan - rates from 4.00% - 4.00% (a)		2022	$	445.0		$	—
First mortgage bonds	1.875%	2016	—			445.0
Pollution control series	4.8%	2036	100.0			100.0
Pollution control series - rates from 1.29% - 1.36% (a) and 1.13% - 1.17% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	18.0			18.1
Unamortized deferred financing costs			(12.3		)	(6.2		)
Unamortized debt discount			(2.2		)	(0.2		)
Total long-term debt			748.5			756.7
Less: current portion			(3.5		)	(443.1		)
Total			$	745.0		$	313.6

(a)Range of interest rates for the nine months ended September 30, 2016.

(b)Range of interest rates for the year ended December 31, 2015.

Significant transactions

On August 24, 2016, DP&L refinanced its 1.875% First Mortgage Bonds Due 2016, with a variable rate Term Loan B of $445.0 million maturing on August 24, 2022 and secured by a pledge of DP&L First Mortgage Bonds. The variable interest rate on the loan is calculated based on LIBOR plus a spread of 3.25%, with a LIBOR floor of 0.75%. Up to the maturity date but not starting until March 31, 2017, the loan amortizes 0.25% of the initial principal balance quarterly, and contains covenants and restrictions that are generally consistent with existing DP&L credit agreements.

Debt covenants and restrictions

DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement have two financial covenants. The first measures Total Debt to Total Capitalization and is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.

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.

Note 7 – Income Taxes

The following table details the effective tax rates for the three and nine months ended September 30, 2016 and 2015.

	Three months ended		Nine months ended
	September 30,		September 30,
	2016	2015	2016	2015
DP&L	39.6%	4.9%	36.7%	24.8%

Income tax expense for the three and nine months ended September 30, 2016 and 2015 was calculated using the estimated annual effective income tax rates for 2016 and 2015 of 36.7% and 29.0%, respectively. For the three and nine months ended September 30, 2016 and 2015 management estimated 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

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applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates.

For the three months ended September 30, 2016, DP&L’s current period effective tax rate was greater than the estimated annual effective rate primarily due to a change in its uncertain tax positions and the deduction for the preferred stock dividends. The increase in the annual effective rate compared to the same period in 2015 is primarily due to a forecasted pre-tax loss in the 2016 tax year.

Note 8 – 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 made during the nine months endedSeptember 30, 2016 and $5.0 million in employer contributions during the nine months endedSeptember 30, 2015.

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 amounts presented for postretirement include both health and life insurance. The pension and postretirement 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. See Note 11 – Related Party Transactions.

The net periodic benefit cost of the pension and postretirement benefit plans for the three and nine months ended September 30, 2016 and 2015 was:

Net Periodic Benefit Cost	Pension
	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
Service cost	$	1.4		$	1.8		$	4.2		$	5.3
Interest cost	3.7			4.2			11.1			12.8
Expected return on plan assets	(5.7		)	(5.6		)	(17.1		)	(16.8		)
Amortization of unrecognized:
Prior service cost	0.8			0.9			2.3			2.5
Actuarial loss	1.8			2.4			5.4			7.2
Net periodic benefit cost	$	2.0		$	3.7		$	5.9		$	11.0

Net Periodic Benefit Cost	Postretirement
	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
Service cost	$	—		$	0.1		$	0.1		$	0.1
Interest cost	0.1			0.1			0.4			0.5
Expected return on plan assets	(0.1		)	(0.1		)	(0.1		)	(0.1		)
Amortization of unrecognized:
Prior service cost	0.1			0.1			0.1			0.1
Actuarial gain	(0.1		)	(0.2		)	(0.5		)	(0.5		)
Net periodic benefit cost	$	—		$	—		$	—		$	0.1

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Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:

$ in millions	Pension		Postretirement
2016	$	6.2	$	0.4
2017	25.2		1.6
2018	25.8		1.5
2019	26.3		1.4
2020	26.7		1.4
2021 - 2025	134.8		5.7

Note 9 – Shareholder’s Equity

DP&L has 250,000,000 authorized $0.01 par value common shares, of which 41,172,173 are outstanding at September 30, 2016. 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 not to have a negative retained earnings balance. After the fixed-asset impairment recorded during the second quarter of 2016 and as of September 30, 2016, DP&L's equity ratio was 50% 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.

On October 13, 2016 (the "Redemption Date"), DP&L redeemed all of its issued and outstanding preferred stock, consisting of the following series: Preferred Stock, 3.75% Series A, Cumulative (the “Series A Stock”); Preferred Stock, 3.75% Series B, Cumulative (the “Series B Stock”); and Preferred Stock, 3.90% Series C, Cumulative (the “Series C Stock” and, together with the Series A Stock and the Series B Stock, the “Preferred Stock”). On the Redemption Date, the Preferred Stock of each series was redeemed at the following prices as specified in DP&L’s Amended and Restated Articles of Incorporation,plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date: a price of $102.50 per share for the Series A Stock, a price of $103.00 per share for the Series B Stock, and a price of $101.00 per share for the Series C Stock. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, andall rights of the holders thereof as shareholders of DP&L, except the right to payment of the redemption price, ceased to exist.

As we issued the notice to redeem the preferred stock in the third quarter, the $23.5 million redemption value was included in Other Current Liabilities as of September 30, 2016. The difference between the carrying value of the Redeemable Preferred Stock and the redemption amount was charged to Other paid-in capital.

In addition, with DP&L preferred stock no longer outstanding, certain provisions in DP&L's Amended Articles of Incorporation which could limit the payment of cash dividends on any of its common stock, no longer apply.

Equity settlement of related party payable

DP&L settled a $7.5 million payable to DPL relating to income taxes. This payable balance was settled through equity and DPL's investment in DP&L was increased by $7.5 million as consideration for extinguishing the payable.

Note 10 – Contractual Obligations, Commercial Commitments and Contingencies

Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in OVEC, which is recorded using the cost method of accounting under GAAP. As of September 30, 2016, DP&L could be responsible for the repayment of 4.9%, or $74.9 million, of a $1,528.0 million debt obligation that has maturities from 2018 to 2040. This would only happen if OVEC defaulted on its debt payments. As of September 30, 2016, we have no knowledge of such a default.

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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, 2015.

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 September 30, 2016, 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 and the Ohio EPA 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 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 – Related Party Transactions

Service Company

Effective January 1, 2014, the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L. The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of other businesses.

Benefit plans

DPL has an agreement with AES or one of its affiliates to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. AES or its affiliate administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments.

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The following table provides a summary of these transactions:

	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
DP&L revenues:
Sales to DPLER (including MC Squared) (a)	$	—		$	66.0		$	—		$	245.0
DP&L Operation & Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(0.8	)	$	(0.8	)	$	(2.5	)	$	(2.4	)
Expense recoveries for services provided to DPLER (c)	$	—		$	0.6		$	—		$	1.8
Transactions with the Service Company:
Charges for services provided	$	9.4		$	7.6		$	29.2		$	24.3
Charges to the Service Company	$	1.1		$	1.1		$	3.3		$	5.0
Transactions with other AES affiliates:
Charges / (credits) for health, welfare and benefit plans	$	3.8		$	4.1		$	5.5		$	11.9
Balances with related parties:							At September 30, 2016			At December 31, 2015
Net payable to the Service Company							$	(1.4	)	$	(0.5	)
Short-term loan with DPL(d)							$	—		$	35.0
Receivable from MVIC (b)							$	4.3		$	2.8

(a) DP&L sold power to DPLER and MC Squared to satisfy the electric requirements of their retail customers. The revenue dollars associated with sales to DPLER and MC Squared are recorded as wholesale revenues in DP&L’s Financial Statements. These agreements were terminated upon the sale of DPLER on January 1, 2016.

(b) MVIC, a wholly-owned captive insurance subsidiary of DPL, provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC. DP&L received insurance proceeds from MVIC of $0.2 million and $0.5 million for the three months ended September 30, 2016 and 2015, respectively, and $0.4 million and $4.3 million for the nine months ended September 30, 2016 and 2015, respectively.

(c) Prior to the sale of DPLER, in the normal course of business DP&L incurred and recorded expenses on behalf of DPLER. Such expenses included but were not limited to employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. DP&L subsequently charged these expenses to DPLER at DP&L’s cost and credited the expense in which they were initially recorded.

(d) On December 31, 2015, DPL loaned $35.0 million to DP&L through an intercompany short-term loan at 2.67%.

Income taxes

AES files federal and state income tax returns which consolidate DPL and its subsidiaries, including DP&L. Under a tax sharing agreement with DPL, DP&L is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. DP&L had a net payable balance of $36.2 million at September 30, 2016 which is recorded in Accounts receivable, net and Accrued taxes on the accompanying Balance Sheets and a net receivable balance of $1.5 million at December 31, 2015 which is recorded in Accounts receivable, net and Accrued taxes on the accompanying Balance Sheets on a gross basis.

Gain on termination of contract

On January 1, 2016, DPL closed on the sale of DPLER. Also on January 1, 2016, DP&L terminated the contract it had with DPLER for the supply of electricity. The agreement terminating the contract was signed on December 28, 2015 and DP&L received $27.7 million of restricted cash on December 31, 2015 for the early termination of the contract. For the nine months ended September 30, 2016, this amount was recorded in Gain on termination of contract in the Condensed Statements of Operations and the cash received was included in Cash flows from operating activities in the Condensed Statements of Cash Flows.

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Note 12 – Fixed-asset Impairment

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 test and determined that the carrying amounts 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 expenses of $292.0 million, $246.2 million and $318.9 million for Stuart, Killen and Zimmer, respectively during the nine months ended September 30, 2016.

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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 a 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 altogether, 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, 2015 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.

POLITICAL FACTORS

The outcome of the 2016 U.S. elections could result in significant changes to U.S. environmental policies, energy policies and tax laws, the impact of which is uncertain.

REGULATORY ENVIRONMENT

DPL’s, DP&L’s and our 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 10 – 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 2016 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. We did not have any accruals for environmental matters as of September 30, 2016. 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, which are disclosed in the paragraphs below. 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.

Clean Water Act rules for Selenium

On July 13, 2016, the USEPA published the final updated chronic aquatic life criterion for the pollutant selenium in freshwater per CWA section 304(a). The rule will be implemented after state rulemaking occurs, which is expected to be at the end of 2017, and requirements will be incorporated into NPDES permits with compliance schedules in some cases. We are reviewing the rule and cannot yet say what the impact will be on our operations.

Cross-State Air Pollution Rule

On September 7, 2016, the USEPA finalized an update to the CSAPR to address the 2008 ozone NAAQS. CSAPR addresses the "good neighbor" provision of the CAA, which prohibits sources within each state from emitting any air

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pollutant in an amount which will contribute significantly to any other state’s nonattainment, or interference with maintenance of, any NAAQS. The final rule finds that NOx ozone season emissions in 22 states (including Ohio) affect the ability of downwind states to attain and maintain the 2008 ozone NAAQS. For these 22 states, the USEPA is issuing federal implementation plans that generally update existing CSAPR NOx ozone season emission budgets for electric generating units within these states, and implement these budgets through modifications to the existing CSAPR NOx ozone season allowance trading program. Implementation will start in the 2017 ozone season (May through September 2017). Affected facilities will receive fewer ozone season NOx allowances in 2017 and later, possiblyresulting in the need to purchase additional allowances. At this time, we cannot predict what the impact will be with respect to these new standards and requirements, but it could be material if certain facilities will need to purchase additional allowances based on reduced allocations.

Regulation of Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers DP&L to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site. On June 8, 2016, the PRP group entered into another Administrative Settlement Agreement and Order on Consent (ASAOC) (the “2016 ASAOC”) for the performance of a remedial investigation and feasibility study. On July 5, 2016, the plaintiffs filed a motion for leave to amend their complaint against DP&L and other defendants, which the Court granted on August 15, 2016. DP&L is unable to predict the outcome of these actions by the plaintiffs and the USEPA. Additionally, the District Court’s 2013 ruling and the Court of Appeals’ affirmation of that ruling in 2014 do not address future litigation that may arise with respect to actual remediation costs. While DP&L is unable to predict the outcome of these and any future matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its business, financial condition or results of operations.

On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCBs). This reassessment is in the early stages and the USEPA is seeking information from potentially affected parties on how it should proceed. A proposed rule is expected in 2017. At present, DP&L is unable to predict the impact of this initiative but it could have a material effect on its results of operations, financial condition or cash flows.

PJM PRICING

Capacity Auction Price

The PJM capacity base residual auction for the 2019/20 period cleared at a per megawatt price of $100/MW-day for our RTO area. The per megawatt prices for the periods 2018/19, 2017/18, 2016/17 and 2015/16 were $165/MW-day, $152/MW-day, $134/MW-day and $136/MW-day, respectively, based on previous auctions. As discussed in our Form 10-K, a new CP program has been approved by the FERC, which will phase out RPM as of the 2018/19 period. During the phase-out period, the RPM auction results were modified based on transitional auctions that were conducted in the third quarter of 2015. 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 $6.2 million and $5.1 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.

At present, DP&L is unable to project whether the CP program will be beneficial or negative to DP&L’s operations, but the results could be material to DP&L’s results of operations, financial position and cash flows.

OHIO COMPETITION AND REGULATORY PROCEEDINGS

Ohio Retail Rates

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.

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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 straight-fixed variable rate design 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.

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.

On August 25, 2016, DP&L filed an application at the FERC under Section 203 of the Federal Power Act requesting authorization to transfer DP&L generation assets to AES Ohio Generation. Several parties have intervened and filed comments or protests. This application is still pending but is not expected to have a material financial impact to DPL or DP&L.

The following tables provide a summary of the number of electric customers and volumes supplied by DPLER while an affiliate and non-affiliated CRES providers in our service territory during the three and nine months ended September 30, 2016 and 2015:

	Three months ended		Three months ended
	September 30, 2016		September 30, 2015
	Electric Customers (a)	Sales (in millions of kWh)	Electric Customers (a)	Sales (in millions of kWh)
Supplied by DPLER while an affiliate	—	—	112,726	991
Supplied by non-affiliated CRES providers	259,978	2,903	124,625	1,656
Total in DP&L's service territory	259,978	2,903	237,351	2,647
Distribution customers/sales by DP&L in our service territory (b)	517,607	3,970	515,372	3,646
	Nine months ended		Nine months ended
	September 30, 2016		September 30, 2015
	Electric Customers (a)	Sales (in millions of kWh)	Electric Customers (a)	Sales (in millions of kWh)
Supplied by DPLER while an affiliate	—	—	112,726	3,094
Supplied by non-affiliated CRES providers	259,978	8,151	124,625	4,525
Total in DP&L's service territory	259,978	8,151	237,351	7,619
Distribution customers/sales by DP&L in our service territory (b)	517,607	11,126	515,372	10,659

(a) Customers at the end of each period.

(b) The volumes supplied by DPLER, prior to its sale on January 1, 2016, represented approximately 27% and 29% of DP&L’s total distribution volumes during the three and nine months ended September 30, 2015, respectively.

DPLER was an affiliated company until its sale on January 1, 2016. While owned by DPL, DPLER was one of the registered CRES providers that marketed competitive transmission and generation services.

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FUEL AND RELATED COSTS

Fuel and Commodity Prices

The coal market is a global market in which domestic prices are affected by international supply disruptions and demand balance. In addition, domestic issues like government-imposed direct costs and permitting issues affect mining costs and supply availability. Our approach is to hedge the fuel costs for our anticipated electric sales. For the year ending December 31, 2016, we have substantially all our coal requirements under contract to meet our committed sales. We may not be able to hedge the entire exposure of our operations from commodity price volatility. If our suppliers do not meet their contractual commitments or we are not hedged against price volatility, our results of operations, financial condition or cash flows could be materially affected.

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RESULTS OF OPERATIONS – DPL

DPL’s results of operations include the results of its subsidiaries, including the consolidated results of 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.

Income Statement Highlights – DPL

	Three months ended September 30,						Nine months ended September 30,
$ in millions	2016			2015			2016			2015
Revenues:
Retail	$	197.4		$	203.2		$	553.1		$	606.3
Wholesale	138.3			142.2			368.0			471.7
RTO revenues	16.8			18.3			47.2			53.8
RTO capacity revenues	32.9			37.3			104.6			113.3
Other revenues	3.9			2.3			8.7			7.0
Total revenues	389.3			403.3			1,081.6			1,252.1
Cost of revenues:
Fuel costs	80.4			72.1			210.9			203.2
Gains from the sale of coal	(1.9		)	(0.5		)	(4.9		)	(0.7		)
Mark-to-market losses / (gains)	0.4			(0.2		)	—			(0.3		)
Total fuel	78.9			71.4			206.0			202.2
Purchased power	86.1			81.9			254.5			280.4
RTO charges	23.2			24.4			60.2			79.5
RTO capacity charges	3.6			35.4			18.5			94.0
Mark-to-market losses / (gains)	(1.2		)	3.2			(2.7		)	4.6
Total purchased power	111.7			144.9			330.5			458.5
Total cost of revenues	190.6			216.3			536.5			660.7
Gross margin (a)	$	198.7		$	187.0		$	545.1		$	591.4
Gross margin as a percentage of revenues	51		%	46		%	50		%	47		%
Operating income / (loss)	$	55.4		$	35.5		$	(111.5	)	$	156.0

(a) For purposes of discussing operating results, we present and discuss gross margins. 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 – 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 September 30,		Nine months ended September 30,
	2016	2015	2016	2015
Heating degree days (a)	31	35	3,212	3,707
Cooling degree days (a)	874	637	1,175	1,048

(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

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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 plants and non-affiliated utility plants to sell into the wholesale market; and weather conditions across the multi-state region. Our plan is to make wholesale sales when market prices allow for the economic operation of our generation facilities when margin opportunities exist between the wholesale sales and power purchase prices.

The following table provides a summary of changes in revenues from the prior period:

	Three months ended			Nine months ended
	September 30,			September 30,
$ in millions	2016 v 2015			2016 v 2015
Retail
Rate	$	(21.4	)	$	(68.4	)
Volume	16.7			14.3
Other miscellaneous	(1.1		)	0.9
Total retail change	(5.8		)	(53.2		)
Wholesale
Rate	(20.5		)	(96.1		)
Volume	16.6			(7.6		)
Total wholesale change	(3.9		)	(103.7		)
RTO revenues and RTO capacity revenues
RTO revenues and RTO capacity revenues	(5.9		)	(15.3		)
Other
Other	1.6			1.7
Total other revenue	1.6			1.7
Total revenues change	$	(14.0	)	$	(170.5	)

During the three months ended September 30, 2016, Revenues decreased $14.0 million to $389.3 million from $403.3 million in the same period of the prior year. This decrease was primarily the result of lower average retail and wholesale rates, partially offset by higher retail volume and higher wholesale volume. The changes in the components of revenue are discussed below:

• Retail revenues decreased $5.8 million primarily due to lower average DP&L retail rates. The decrease in retail rates was primarily driven by decreased retail revenue from SSO customers as the competitive auction rate, which represents 100% of DP&L SSO load in 2016 compared to 60% in 2015, is lower than the non-auction generation rate. Warmer summer weather in 2016 contributed to the volume increase as cooling degree days increased by 237. The aforementioned impacts resulted in an unfavorable $21.4 million retail price variance and a favorable $16.7 million retail volume variance. In addition, there was an unfavorable $1.1 million variance in other miscellaneous retail revenues.

• Wholesale revenues decreased $3.9 million primarily as a result of an unfavorable $20.5 million wholesale price variance and a favorable $16.6 million wholesale volume variance. The price decrease of $20.5 million was primarily due to lower market prices in 2016 and higher prices on sales to DPLER in 2015. This price decrease was partially offset by a favorable wholesale volume variance due to the fact that DP&L had excess generation available to be sold in the wholesale market in 2016 resulting from 100% of its SSO load being served through the competitive bid process compared to 60% during 2015. In addition, there was a 10.2% increase in internal generation from DP&L's co-owned and operated plants in 2016 compared to the

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prior year. This favorable wholesale volume variance was partially offset by a decrease in volume due to the sale of DPLER, as DP&L previously had full requirements sales to DPLER in 2015. These sales were previously eliminated in consolidation prior to DPLER being a discontinued operation.

• 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 capacity payments under the RPM construct, decreased $5.9 million compared to the prior year. This decrease was the result of a $1.5 million decrease in RTO transmission and congestion revenue and a $4.4 million decrease in revenue realized from the PJM capacity auction due to lower capacity cleared in the auction. The capacity prices that became effective in June 2016 were $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction, compared to $136/MW-day in June 2015.

During the nine months ended September 30, 2016, Revenues decreased $170.5 million to $1,081.6 million from $1,252.1 million in the same period of the prior year. This decrease was primarily the result of lower retail rates, lower wholesale rates, and lower wholesale volumes, partially offset by higher retail volumes. The changes in the components of revenue are discussed below:

• Retail revenues decreased $53.2 millionprimarily due to lower average DP&L retail rates. The decrease in retail rates was primarily driven by decreased retail revenue from SSO customers as the competitive auction rate, which represents 100% of DP&L SSO load in 2016 compared to 60% in 2015, is lower than the non-auction generation rate. Warmer weather in 2016 contributed to the volume increase as cooling degree days increased by 127 along with increased sales to commercial and industrial customers. The aforementioned impacts resulted in an unfavorable $68.4 million retail price variance and a favorable $14.3 million retail volume variance. In addition, there was a favorable other miscellaneous variance of $0.9 million.

• Wholesale revenues decreased $103.7 million primarily as a result of an unfavorable $96.1 million wholesale price variance and an unfavorable $7.6 million wholesale volume variance. The price decrease of $96.1 million was primarily due to lower market prices in 2016 and higher prices on sales to DPLER in 2015. Although DP&L had excess generation available to be sold in the wholesale market in 2016 resulting from 100% of its SSO load being served through the competitive bid process compared to 60% during 2015, DPL had a decrease in volume due to the sale of DPLER, as DP&L previously had full requirements sales to DPLER in 2015. These sales were previously eliminated in consolidation prior to DPLER being reported as a discontinued operation.

• 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 capacity payments under the RPM construct, decreased $15.3 million compared to the prior year. This decrease was the result of a $6.6 million decrease in RTO transmission and congestion revenue, as 2015 congestion revenue charges were higher due to the fact that the winter weather was milder in 2016 than 2015. There was also an $8.7 million decrease in revenue realized from the PJM capacity auction in 2016 due to plant outages in the first quarter and lower capacity cleared in the auction. The capacity prices that became effective in June 2016 were $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction, compared to $136/MW-day in June 2015 and $126/MW-day in June 2014.

DPL – Cost of Revenues

During the three months ended September 30, 2016, 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, increased $7.5 million compared to the same period in the prior year primarily due to a 15.7% increase in internal generation, partially offset by a 3.7% decrease in average fuel cost per MWh.

• Net purchased power decreased $33.2 million compared to the same period in the prior year. This decrease was driven by the following factors:

◦ Purchased power increased $4.2 million compared to the same period in the prior year primarily due to an unfavorable price variance of $10.5 million driven by prices in the competitive bid process. This unfavorable price variance was partially offset by a $6.3 million volume decrease

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compared to the same period in the prior year as DP&L no longer purchases power to source DPLER customers due to the sale of DPLER on January 1, 2016. This volume decrease was partially offset by increased purchases as DP&L now sources 100% of SSO load through the competitive bid process in 2016 as opposed to 60% in 2015. DPL purchases power for the SSO load sourced through the competitive bid process and to serve auction load requirements in service territories other than DP&L's territory.

◦ RTO charges decreased $1.2 million compared to the same period in the prior year primarily as a result of no longer having a DP&L retail load obligation as a result of 100% SSO sales being sourced through the competitive auction. The remaining charges primarily relate to serving the loads of other parties through their competitive bid process. RTO charges are incurred by DP&L as a member of PJM and primarily include costs associated with load obligations for retail customers.

◦ RTO capacity charges decreased $31.8 million compared to the same period in the prior year primarily due to DP&L no longer having a retail load requirement in 2016, resulting from the SSO load being 100% sourced through competitive bid in 2016 as opposed to 60% in 2015 and resulting from the fact that DP&L no longer provides power to DPLER in 2016. The remaining charges primarily relate to serving the load of other parties through their competitive bid process. As noted in the revenue section above, RTO capacity prices are set through PJM's annual auction.

◦ Mark-to-market losses decreased $4.4 million compared to the same period in the prior year primarily due to less significant decreases in power prices in the three month period ended September 30, 2016, causing lower losses on derivative forward power purchase contracts.

During the nine months ended September 30, 2016, Cost of Revenues decreased $124.2 million compared to the same period in the prior year:

• Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $3.8 million compared to the same period in the prior year primarily due to a 5.5% increase in internal generation, partially offset by a 1.7% decrease in average fuel cost per MWh.

• Net purchased power decreased $128.0 million compared to the same period in the prior year. This decrease was driven by the following factors:

◦ Purchased power decreased $25.9 million compared to the same period in the prior year primarily due to a $51.2 million volume decrease as DP&L no longer purchases power to source DPLER customers due to the sale of DPLER on January 1, 2016. This was partially offset by increased purchases as DP&L now sources 100% of SSO load through the competitive bid process in 2016 as opposed to 60% in 2015. DPL purchases power for the SSO load sourced through the competitive bid process and to serve auction load requirements in service territories other than DP&L's. The decrease in volume was offset by an unfavorable price variance of $25.3 million driven by higher prices in the competitive bid process.

◦ RTO charges decreased $19.3 million compared to the same period in the prior year primarily as a result of no longer having a DP&L retail load obligation as a result of 100% SSO sales being sourced through the competitive auction. The remaining charges primarily relate to serving the loads of other parties through their competitive bid process. RTO charges are incurred by DP&L as a member of PJM and primarily include costs associated with load obligations for retail customers.

◦ RTO capacity charges decreased $75.5 million compared to the same period in the prior year primarily due to DP&L no longer having a retail load requirement in 2016, resulting from the SSO load being 100% sourced through competitive bid in 2016 as opposed to 60% in 2015 and resulting from the fact that DP&L no longer provides power to DPLER in 2016. The remaining charges primarily relate to serving the load of other parties through their competitive bid process. As noted in the revenue section above, RTO capacity prices are set by an annual auction.

◦ Mark-to-market losses decreased $7.3 million compared to the same period in the prior year due to less significant decreases in power prices in the nine month period ended September 30, 2016, causing lower losses on derivative forward power purchase contracts.

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DPL – Operation and Maintenance

The following table provides a summary of changes in Operation and maintenance expense from the prior year periods:

	Three months ended			Nine months ended
	September 30,			September 30,
$ in millions	2016 v 2015			2016 v 2015
Deferred storm costs (a)	$	(4.4	)	$	(13.1	)
Generating facilities operating and maintenance expenses	(2.0		)	(8.1		)
Group insurance / Long-term disability	0.9			(4.4		)
Reversal of Economic Development Fund accrual	(1.7		)	(1.7		)
Retirement benefits	(1.2		)	(0.7		)
Alternative energy and maintenance expenses (a)	4.9			12.6
Low-income payment program (a)	1.9			4.9
Maintenance of overhead transmission and distribution lines	(0.9		)	1.1
Other, net	(1.8		)	(0.8		)
Total change in operation and maintenance expense	$	(4.3	)	$	(10.2	)

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

During the three months ended September 30, 2016, Operation and maintenance expense decreased $4.3 million compared to the same period in the prior year.

This variance was primarily the result of:

• decreased storm costs, which were recognized in 2015 as they were recovered through customer rates;

• decreased maintenance expenses at our generating facilities;

• decreased expenses due to the reversal of the Economic Development Fund expense, resulting from the withdrawal of ESP 2;

• decreased retirement benefits; and

• decreased maintenance of overhead transmission and distribution lines.

These decreases were partially offset by:

• increased expenses related to alternative energy and energy efficiency programs, which have a corresponding offset in Revenues associated with these programs;

• increased expenses for the low-income payment program, which is funded by the USF revenue rate rider; and

• increased group insurance/long-term disability expenses.

During the nine months ended September 30, 2016, Operation and maintenance expense decreased $10.2 million, compared to the same period in the prior year.

This variance was primarily the result of:

• decreased storm costs, which were recognized in 2015 as they were recovered through customer rates;

• decreased maintenance expenses at our generating facilities;

• decreased group insurance/long-term disability expenses associated with participation in the AES self-insurance plan;

• decreased expenses due to the reversal of the Economic Development Fund expense, resulting from the withdrawal of ESP 2; and

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• decreased retirement benefits.

These decreases were offset by:

• increased expenses related to alternative energy and energy efficiency programs, which have a corresponding offset in Revenues associated with these programs;

• increased expenses for the low-income payment program, which is funded by the USF revenue rate rider; and

• increased maintenance of overhead transmission and distribution lines, due to storms.

DPL – Depreciation and Amortization

During the three months ended September 30, 2016, Depreciation and amortization expense decreased $2.9 millioncompared to the same period in the prior year, primarily due to the fixed asset impairment in June 2016, which reduced depreciation expense due to the lower asset values.

During the nine months ended September 30, 2016, Depreciation and amortization expense decreased $0.6 millioncompared to the same period in the prior year, primarily due to the fixed asset impairment in June 2016, which reduced depreciation expense due to the lower asset values. This was partially offset by an increase in the ARO for asbestos removal and remediation at the closed Beckjord plant. As this plant is no longer in operation, the entire impact of the adjustment was recorded as depreciation expense.

DPL – General Taxes

During the three months ended September 30, 2016, General taxes did not change significantly from the same period in the prior year.

During the nine months ended September 30, 2016, General taxes decreased $2.5 million compared to the same period in the prior year. This decrease primarily resulted from a $1.6 million true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016, as well as lower 2016 Commercial Activities Tax resulting from lower taxable revenue.

DPL – Fixed-asset Impairment

During the nine months ended September 30, 2016, DPL recorded an impairment of fixed assets of $235.5 million. The 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. DPL 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 Impairment of Notes to DPL's Condensed Financial Statements.

DPL – Charge for Early Redemption of Debt

During the three months ended September 30, 2016, the charge for early redemption of debt decreased $1.6 million due to the refinancing of DP&L's revolving credit facility and pollution control bonds in the same period in the prior year.

During the nine months ended September 30, 2016, the charge for early redemption of debt increased $1.0 million primarily due to the February 2016 make-whole premium of $2.4 million associated with the early retirement of $73.0 million of the 6.5% Senior Notes due in 2016.

DPL – Interest Expense

Interest expense during the three and nine months ended September 30, 2016 decreased $1.9 million and $11.0 million, respectively, compared to the same periods in the prior year primarily due to debt repayments at DPL and DP&L, as well as decreased interest rates on DP&L’s senior secured pollution control bonds and reduced carrying costs on regulatory assets.

DPL – Income Tax Expense

During the three months ended September 30, 2016, Income tax expense increased $14.1 million compared to the same period in the prior year primarily due to higher pre-tax income and an anticipated refund from the IRS for the filing, in the prior year, of an amended 2011 tax return for the predecessor company.

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During the nine months ended September 30, 2016, Income tax expense decreased $90.4 million compared to the same period in the prior year primarily due to a pre-tax loss in the current year.

RESULTS OF OPERATIONS – DP&L

Income Statement Highlights – DP&L

	Three months ended September 30,						Nine months ended September 30,
$ in millions	2016			2015			2016			2015
Revenues:
Retail	$	197.7		$	203.6		$	554.1		$	607.5
Wholesale	127.9			138.9			347.2			451.4
RTO revenues	15.2			16.4			43.9			50.3
RTO capacity revenues	27.6			30.3			86.2			93.4
Other mark-to-market losses	—			—			(0.1		)	—
Total revenues	368.4			389.2			1,031.3			1,202.6
Cost of revenues:
Fuel costs	72.5			69.7			194.4			189.9
Gains from the sale of coal	(1.9		)	(0.5		)	(4.9		)	(0.7		)
Mark-to-market losses / (gains)	0.4			(0.2		)	—			(0.3		)
Total fuel	71.0			69.0			189.5			188.9
Purchased power	85.3			82.1			254.2			280.5
RTO charges	22.7			24.0			59.1			75.8
RTO capacity charges	3.3			33.4			17.4			91.4
Mark-to-market losses / (gains)	(1.3		)	3.0			(2.7		)	4.6
Total purchased power	110.0			142.5			328.0			452.3
Total cost of revenues	181.0			211.5			517.5			641.2
Gross margin (a)	$	187.4		$	177.7		$	513.8		$	561.4
Gross margin as a percentage of revenues	51		%	46		%	50		%	47		%
Operating income / (loss)	$	56.6		$	28.5		$	(721.8	)	$	130.9

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

DP&L – Revenues

Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, DP&L’s retail sales volume is impacted by the number of heating and cooling degree days occurring during a year.

The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting DP&L’s wholesale sales volume each hour throughout the year include: wholesale market prices, retail demand throughout the entire wholesale market area, DP&L and non-DP&L plants’ availability to sell into the wholesale market and weather conditions across the multi-state region. DP&L’s plan is to make wholesale sales when market prices allow for the economic operation of its generation facilities.

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The following table provides a summary of changes in revenues from the prior period:

	Three months ended			Nine months ended
	September 30,			September 30,
$ in millions	2016 v 2015			2016 v 2015
Retail
Rate	$	(21.6	)	$	(69.1	)
Volume	16.5			13.6
Other miscellaneous	(0.8		)	2.1
Total retail change	(5.9		)	(53.4		)
Wholesale
Rate	(20.3		)	(84.4		)
Volume	9.3			(19.8		)
Total wholesale change	(11.0		)	(104.2		)
RTO revenues and RTO capacity revenues
RTO revenues and RTO capacity revenues	(3.9		)	(13.6		)
Other
Unrealized MTM	—			(0.1		)
Total revenues change	$	(20.8	)	$	(171.3	)

During the three months ended September 30, 2016, Revenues decreased $20.8 million to $368.4 million from $389.2 million in the same period in the prior year. This decrease was primarily the result of lower average retail rates and lower average wholesale rates, partially offset by higher retail volume and higher wholesale volume. The changes in the components of revenue are discussed below:

• Retail revenues decreased $5.9 millionprimarily due to lower average retail rates. The decrease in retail rates is primarily driven by decreased retail revenue from SSO customers as the competitive auction rate, which represents 100% of DP&L SSO load in 2016 as compared to 60% in 2015, is lower than our non-auction generation rate. Warmer summer weather in 2016 contributed to the volume increase as cooling degree days increased by 237. The aforementioned impacts resulted in an unfavorable $21.6 million retail price variance and a favorable $16.5 million retail volume variance. There was also an unfavorable other miscellaneous variance of $0.8 million.

• Wholesale revenues decreased $11.0 millionprimarily as a result of an unfavorable $20.3 million wholesale price variance and a favorable $9.3 million wholesale volume variance. The price decrease of $20.3 million was primarily due to lower market prices in 2016 and higher prices on sales to DPLER in 2015. This price decrease was partially offset by a favorable wholesale volume variance due to the fact that DP&L had excess generation available to be sold in the wholesale market in 2016 resulting from 100% of its SSO load being served through the competitive bid process compared to 60% during 2015. In addition, there was a 10.2% increase in internal generation from DP&L's co-owned and operated plants in 2016 compared to the prior year. This favorable wholesale volume variance was partially offset by a decrease in volume due to the contract termination with DPLER, as DP&L previously had full requirements sales to DPLER in 2015.

• 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 capacity payments under the RPM construct, decreased $3.9 million. This decrease was primarily the result of a $1.2 million decrease in RTO transmission and congestion revenue and a $2.7 million decrease in revenue realized from the PJM capacity auction due to lower capacity cleared in the auction. The capacity prices that became effective in June 2016 were $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction, compared to $136/MW-day in June 2015.

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During the nine months ended September 30, 2016, Revenues decreased $171.3 million to $1,031.3 million from $1,202.6 million in the same period in the prior year. This decrease was primarily the result of lower average retail rates, lower average wholesale rates, and lower wholesale volume, partially offset by higher retail volume. The changes in the components of revenue are discussed below:

• Retail revenues decreased $53.4 millionprimarily due to lower average retail rates. The decrease in retail rates is primarily driven by decreased retail revenue from SSO customers as the competitive auction rate, which represents 100% of DP&L SSO load in 2016 as compared to 60% in 2015, is lower than our non-auction generation rate. Warmer weather in 2016 contributed to the volume increase as cooling degree days increased by 127 along with increased sales to commercial and industrial customers. The aforementioned impacts resulted in an unfavorable $69.1 million retail price variance and a favorable $13.6 million retail volume variance. In addition, there was a favorable other miscellaneous variance of $2.1 million.

• Wholesale revenues decreased $104.2 millionprimarily as a result of an unfavorable $84.4 million wholesale price variance and an unfavorable $19.8 million wholesale volume variance. The price decrease of $84.4 million was primarily due to lower market prices in 2016 and higher prices on sales to DPLER in 2015. Although DP&L had excess generation available to be sold in the wholesale market in 2016 resulting from 100% of its SSO load being served through the competitive bid process compared to 60% during 2015, DP&L had a decrease in volume due to the contract termination with DPLER, as DP&L previously had full requirements sales to DPLER in 2015.

• 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 capacity payments under the RPM construct, decreased $13.6 million. This decrease was the result of a $6.4 million decrease in RTO transmission and congestion revenue, as 2015 congestion revenue charges were higher due to the fact that the winter weather was milder in 2016 than 2015. There was also a $7.2 million decrease in revenue realized from the PJM capacity auction in 2016 due to plant outages in the first quarter and lower capacity cleared in the auction.The capacity prices that became effective in June 2016 were $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction, compared to $136/MW-day in June 2015 and $126/MW-day in June 2014.

DP&L – Cost of Revenues

During the three months ended September 30, 2016, Cost of Revenues decreased $30.5 million compared to the same period in the prior year:

• Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $2.0 millionprimarily due to a 10.2% increase in internal generation, partially offset by a 5.5% decrease in average fuel cost per MWh.

• Net purchased power decreased $32.5 million compared to the prior year. This decrease was driven by the following factors:

◦ Purchased power increased $3.2 million compared to the same period in the prior year primarily due to a $9.9 million price increase driven by higher prices in the competitive bid process. This price increase was partially offset by a volume decrease of $6.7 million. The volume decrease was primarily attributable to the fact that DP&L no longer purchases power to source DPLER customers due to the DPLER contract termination associated with the sale of DPLER by DPL on January 1, 2016. The volume decrease due to the contract termination was partially offset by increased purchases as DP&L now sources 100% of SSO load through the competitive bid process in 2016 as opposed to 60% in 2015. DP&L purchases power for the SSO load sourced through the competitive bid process and to serve auction load requirements in service territories other than DP&L's.

◦ RTO charges decreased $1.3 million compared to the same period in the prior year primarily as a result of no longer having a DP&L retail load obligation as a result of 100% SSO sales being sourced through the competitive auction.The remaining charges primarily relate to serving the loads of other parties through their competitive bid process. RTO charges are incurred as a member of PJM and primarily include costs associated with load obligations for retail customers.

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◦ RTO capacity charges decreased $30.1 million compared to the same period in the prior year primarily due to DP&L no longer having a retail load requirement in 2016, resulting from the SSO load being 100% sourced through competitive bid in 2016 as opposed to 60% in 2015 and resulting from the fact that DP&L no longer provides power to DPLER in 2016. The remaining charges primarily relate to serving the load of other parties through their competitive bid process. As noted in the revenue section above, RTO capacity prices are set by an annual auction.

◦ Mark-to-market losses decreased $4.3 million compared to the same period in the prior year due to less significant decreases in power prices in the three month period ended September 30, 2016, causing lower losses on derivative forward power purchase contracts.

During the nine months ended September 30, 2016, Cost of Revenues decreased $123.7 million compared to the same period in the prior year:

• Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $0.6 million, compared to the same period in the prior year primarily due to a 2.4% increase in internal generation, partially offset by $4.2 million of increased gains from coal sales.

• Net purchased power decreased $124.3 million compared to the prior year. This decrease was driven by the following factors:

◦ Purchased power decreased $26.3 million compared to the same period in the prior year primarily due to a $51.5 million volume decrease largely attributable to the fact that DP&L no longer purchases power to source DPLER customers due to the DPLER contract termination associated with the sale of DPLER by DPL on January 1, 2016. The decrease in volume due to the sale of DPLER was partially offset by increased purchases as DP&L now sources 100% of SSO load through the competitive bid process in 2016 as opposed to 60% in 2015. DP&L purchases power for the SSO load sourced through the competitive bid process and to serve auction load requirements in service territories other than DP&L's. The decrease in volume was also partially offset by an unfavorable price variance of $25.2 million driven by prices in the competitive bid process.

◦ RTO charges decreased $16.7 million compared to the same period in the prior year primarily as a result of no longer having a DP&L retail load obligation as a result of 100% SSO sales being sourced through the competitive auction.The remaining charges primarily relate to serving the loads of other parties through their competitive bid process. RTO charges are incurred as a member of PJM and primarily include costs associated with load obligations for retail customers.

◦ RTO capacity charges decreased $74.0 million compared to the same period in the prior year primarily due to DP&L no longer having a retail load requirement in 2016, resulting from the SSO load being 100% sourced through competitive bid in 2016 as opposed to 60% in 2015 and resulting from the fact that DP&L no longer provides power to DPLER in 2016. The remaining charges primarily relate to serving the load of other parties through their competitive bid process. As noted in the revenue section above, RTO capacity prices are set by an annual auction.

◦ Mark-to-market losses decreased $7.3 million compared to the same period in the prior year due to less significant decreases in power prices in the nine month period ended September 30, 2016, causing lower losses on derivative forward power purchase contracts.

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DP&L – Operation and Maintenance

The following table provides a summary of changes in Operation and maintenance expense from the prior year periods:

	Three months ended			Nine months ended
	September 30,			September 30,
$ in millions	2016 v 2015			2016 v 2015
Deferred storm costs (a)	$	(4.4	)	$	(13.1	)
Generating facilities operating and maintenance expenses	(3.1		)	(11.5		)
Group insurance / Long-term disability	1.1			(3.9		)
Insurance recoveries	(3.4		)	(3.1		)
Reversal of Economic Development Fund accrual	(1.7		)	(1.7		)
Retirement benefits	(1.4		)	(1.3		)
Alternative energy and maintenance expenses (a)	4.9			12.6
Low-income payment program (a)	1.9			4.9
Maintenance of overhead transmission and distribution lines	(0.9		)	1.1
Other, net	(1.0		)	2.4
Total change in operation and maintenance expense	$	(8.0	)	$	(13.6	)

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

During the three months ended September 30, 2016, Operation and maintenance expense decreased $8.0 million, compared to the same period in the prior year.

This variance was primarily the result of:

• decreased storm costs, which were recognized in 2015 as they were recovered through customer rates;

• decreased maintenance expenses at our generating facilities;

• insurance recoveries from MVIC;

• decreased expenses due to the reversal of the Economic Development Fund expense, resulting from the withdrawal of ESP 2;

• decreased retirement benefit costs; and

• decreased maintenance of overhead transmission and distribution lines.

These decreases were offset by:

• increased expenses related to alternative energy and energy efficiency programs, which have a corresponding offset in Revenues associated with these programs;

• increased expenses for the low-income payment program, which is funded by the USF revenue rate rider; and

• increased group insurance/long-term disability expenses;

During the nine months ended September 30, 2016, Operation and maintenance expense decreased $13.6 million, compared to the same period in the prior year.

This variance was primarily the result of:

• decreased storm costs, which were recognized in 2015 as they were recovered through customer rates;

• decreased maintenance expenses at our generating facilities;

• decreased group insurance/long-term disability expenses due to the resolution of uncertainties associated with our participation in the AES self-insurance plan in the second quarter of 2016;

• insurance recoveries from MVIC;

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• decreased expenses due to the reversal of the Economic Development Fund expense, resulting from the withdrawal of ESP 2; and

• decreased retirement benefit costs.

These decreases were offset by:

• increased expenses related to alternative energy and energy efficiency programs, which have a corresponding offset in Revenues associated with these programs;

• increased expenses for the low-income payment program, which is funded by the USF revenue rate rider; and

• increased maintenance of overhead transmission and distribution lines, due to storms.

DP&L – Depreciation and Amortization

During the three months ended September 30, 2016, Depreciation and amortization expense decreased $10.5 million compared to the same period in the prior year, primarily due to the fixed asset impairment in June 2016, which reduced depreciation expense due to the lower asset values.

During the nine months ended September 30, 2016, Depreciation and amortization expense decreased $8.3 million compared to the same period in the prior year, primarily due to the fixed asset impairment in June 2016, which reduced depreciation expense due to the lower asset values. In addition, there was an increase in the ARO for asbestos removal and remediation at the closed Beckjord plant. As this plant is no longer in operation, the entire impact of this adjustment was recorded as depreciation expense.

DP&L – General Taxes

During the three months ended September 30, 2016, General taxes did not change significantly from the same period in the prior year.

During the nine months ended September 30, 2016, General taxes decreased $2.2 million compared to the same period in the prior year. This decrease primarily resulted from a $1.6 million true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016, as well as lower 2016 Commercial Activities Tax resulting from lower taxable revenue.

DP&L – Fixed-asset Impairment

During the nine months ended September 30, 2016, DP&L recorded an impairment of fixed assets of $857.1 million. The 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. DP&L performed a long-lived asset impairment test and determined that the carrying amounts of the asset groups of Stuart, Killen and Zimmer were not recoverable. For more information, see Note 12 – Fixed-asset Impairment of Notes to DP&L's Condensed Financial Statements.

DP&L – Charge for Early Redemption of Debt

During the three and nine months ended September 30, 2016, the charge for early redemption of debt decreased $4.5 million primarily due to the refinancing of DP&L's revolving credit facility and pollution control bonds in the same periods in the prior year.

DP&L – Interest Expense

Interest expense during the three and nine months ended September 30, 2016 decreased $0.4 million and $7.4 million, respectively, compared to the same periods in the prior year. This decrease was primarily due to debt repayments at DP&L, as well as decreased interest rates on DP&L’s senior secured pollution control bonds and reduced carrying costs on regulatory assets.

DP&L – Income Tax Expense

During the three months ended September 30, 2016, Income tax expense increased $18.9 million compared to the same period in the prior year primarily due to higher pre-tax income and an anticipated refund from the IRS for the filing, in the prior year, of an amended 2011 tax return for the predecessor company.

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During the nine months ended September 30, 2016, Income tax expense decreased $296.6 million compared to the same period in the prior year primarily due to a pre-tax loss in the current year.

FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS

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.

The significant items that have affected the cash flows for DPL and DP&L are discussed in greater detail below:

DPL - Cash flowsfromoperating activities

The revenue from our utility business continues to be the principal source of cash from operating activities while our primary uses of cash include payments for fuel, purchased power, operation and maintenance expenses, interest and taxes. Net cash provided by operating activitiesdecreased $61.8 million to $198.6 million in the nine months endedSeptember 30, 2016 from $260.4 million in the nine months endedSeptember 30, 2015. This was primarily driven by a decrease in net income / (loss) adjusted for non-cash items (depreciation and amortization, deferred income taxes, gain on sale of business, and fixed-asset impairment) of $47.3 million, as well as unfavorable changes in net working capital.

DP&L - Cash flowsfromoperating activities

The revenue from our utility business continues to be the principal source of cash from operating activities while our primary uses of cash include payments for fuel, purchased power, operation and maintenance expenses, interest and taxes. Net cash provided by operating activitiesdecreased $27.3 million to $220.4 million in the nine months endedSeptember 30, 2016 from $247.7 million in the nine months endedSeptember 30, 2015. This change was primarily driven by unfavorable changes in working capital.

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 used in investing activitiesdecreased $66.1 million to $(23.1) million in the nine months endedSeptember 30, 2016 from $(89.2) million, in the nine months endedSeptember 30, 2015, primarily driven by $75.5 million in proceeds from the sale of DPLER in January 2016, which was partially offset by an increase in capital expenditures of $16.3 million, related primarily to transmission and distribution activities.

DP&L - Cash flows from investing activities

Net cash used in investing activitiesincreased $2.7 million to $(86.6) million in thenine months endedSeptember 30, 2016 from $(83.9) million in the nine months endedSeptember 30, 2015, primarily due to an increase in capital expenditures of $7.1 million, related primarily to transmission and distribution activities, partially offset by a $2.3 million increase due to the change in restricted cash.

DPL - Cash flows from financing activities

Net cash used in financing activities was $(86.1) million in thenine months endedSeptember 30, 2016 compared to $(145.2) million from financing activities for the nine months endedSeptember 30, 2015. This was due to the redemption of $73.0 million of DPL's $130.0 million 6.5% Senior Unsecured Notes Due 2016, the related make-whole payment of $2.4 million, and deferred financing cost payments of $8.0 million.

DP&L - Cash flows from financing activities

Net cash used in financing activities was $(86.6) million in the nine months endedSeptember 30, 2016 compared to $(158.5) million in the nine months endedSeptember 30, 2015 primarily due to higher net debt payments in the prior year.

Liquidity

We expect our existing sources of liquidity to remain sufficient to meet our anticipated operating needs. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to energy hedges and dividend payments. In 2016 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.

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DP&L’s $445 million 1.875% Taxable First Mortgage Bonds due September 15, 2016 were refinanced prior to maturity with a $445 million variable rate Term Loan B maturing on August 24, 2022.

DPL's $57.0 million senior secured notes matured on October 15, 2016 and were redeemed with cash on hand.

At the filing date of this quarterly report on Form 10-Q, DP&L and DPL have access to the following revolving credit facilities:

$ in millions	Type	Maturity	Commitment		Amounts available as of filing date
DP&L	Revolving	July 2020	$	175.0	$	158.6
DPL	Revolving	July 2020	205.0		203.2
			$	380.0	$	361.8

DP&L has an unsecured revolving credit agreement with a syndicated bank group with a borrowing limit of $175.0 million and a $50.0 million letter of credit sublimit, as well as a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million. This facility expires in July 2020. At the filing date of this quarterly report on Form 10-Q, DP&L had drawn $15.0 million under this facility and had two letters of credit in the amount of $1.4 million outstanding, with the remaining $158.6 million available to DP&L. Fees associated with this letter of credit facility were not material during the nine months ended September 30, 2016 or 2015.

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 September 30, 2016, there were two letters of credit in the amount of $1.8 million outstanding under this facility, with the remaining $203.2 million available to DPL. Fees associated with this facility were not material during the nine months endedSeptember 30, 2016 or 2015.

Cash and cash equivalents for DPL and DP&L amounted to $121.8 million and $92.9 million, respectively, at September 30, 2016. At that date, neither DPL nor DP&L had any short-term investments that were not included in cash and cash equivalents.

Capital Requirements

Planned construction additions for 2016 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 $437.0 million in capital projects for the period 2016 through 2018, of which $310.0 million is projected to be spent by DP&L. DP&L is subject to the mandatory reliability standards of NERC and Reliability First Corporation (RFC), one of the eight NERC regions of which DP&L is a member. DP&L anticipates spending approximately $6.7 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.

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

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exceed 5.75 to 1.00 for any fiscal quarter ending March 31, 2020 through July 31, 2020. As of September 30, 2016, the financial covenant was met with a ratio of 5.40 to 1.00.

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 September 30, 2016, this financial covenant was met with a ratio of 3.33 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) this covenant shall be 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. As of September 30, 2016, DP&L met this financial covenant with a ratio of 0.50 to 1.00. 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.

The DP&L revolving credit facility and Bond Purchase and Covenants Agreement also have an EBITDA to Interest Expense financial covenant that will be 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 September 30, 2016, this covenant was met with a ratio of 13.66 to 1.00.

Debt and Credit Ratings

The following table presents 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	BB (b)	BBB- (c)	Negative	June 2016

The following table presents 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	June 2016

(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.

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.

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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 10 – 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 2016 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 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 and natural gas futures at September 30, 2016 would not have a significant effect on Net income.

At September 30, 2016, a 10% increase or decrease in the market price of our forward power purchase contracts would result in an impact on unrealized gains/losses of $6.0 million, while a 10% increase or decrease in the market price of our forward power sale contracts would result in an impact on unrealized gains/losses of $5.0 million.

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Wholesale Revenues

Energy in excess of contracted obligations is sold in the wholesale spot market when we can identify opportunities with positive margins. DP&L’s electric revenues in the wholesale market include sales to DPLER in 2015. The following table presents the percentages of DPL’s and DP&L’s electric revenue derived from wholesale sales.

DPL	Nine months ended
	September 30,
	2016		2015
Percent of electric revenues from wholesale market	34	%	38	%
DP&L	Nine months ended
	September 30,
	2016		2015
Percent of electric revenues from wholesale market	34	%	38	%

The following table presents the effect on annual Net income (net of estimated income taxes at 35%) as of September 30, 2016, 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	$	32.2	$	30.7

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 2015/16 through 2019/20 are as follows:

	PJM Delivery Year
($/MW-day)	2015/16		2016/17		2017/18		2018/19		2019/20
Capacity clearing price	$	136	$	134	$	152	$	165	$	100

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

	Calendar Year
($/MW-day)	2015		2016		2017		2018		2019
Computed average capacity price	$	132	$	135	$	145	$	159	$	127

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.

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 September 30, 2016 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	$	6.2	$	5.1

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.

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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 nine months endedSeptember 30, 2016 were 39% and 26%, respectively. We have a significant portion of projected 2016 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 2016, 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 2016 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 September 30, 2016 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	$	39.7	$	40.1

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 $125.0 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 pollution control 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 6 – Debt of Notes to DPL’s Condensed Consolidated Financial Statements and Note 6 – Debt of Notes to DP&L’s Condensed Financial Statements.

Principal Payments and Interest Rate Detail by Contractual Maturity Date

The principal value of DPL’s debt was $1,940.6 million at September 30, 2016, consisting of DPL’s unsecured notes and unsecured term loan, along with DP&L’s first mortgage bonds, tax-exempt pollution control bonds and the Wright-Patterson Air Force Base note. All of DPL’s debt was adjusted to fair value at the date of the Merger. The fair value of this debt at September 30, 2016 was $1,969.4 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DPL’s debt obligations that are sensitive to interest rate changes:

DPL
	Principal payments due												At September 30, 2016
	during the twelve months ending
	September 30,												Principal		Fair
$ in millions	2017		2018		2019		2020		2021		Thereafter		Amount		Value
Variable-rate debt	$	22.1	$	29.5	$	29.5	$	260.7	$	4.5	$	423.7	$	770.0	$	770.0
Average interest rate (a)	3.0%		3.0%		3.0%		1.7%		4.0%		4.0%
Fixed-rate debt	$	57.1	$	0.1	$	0.2	$	200.2	$	0.2	$	912.8	1,170.6		1,199.4
Average interest rate	6.5%		4.2%		4.2%		6.7%		4.2%		6.9%
Total													$	1,940.6	$	1,969.4

(a) Based on rates in effect at September 30, 2016

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The principal value of DP&L’s debt was $763.0 million at September 30, 2016, consisting of its first mortgage bonds, tax-exempt pollution control bonds and the Wright-Patterson Air Force Base note. The fair value of this debt was $763.5 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 September 30, 2016
	during the twelve months ending
	September 30,												Principal		Fair
$ in millions	2017		2018		2019		2020		2021		Thereafter		Amount		Value
Variable-rate debt	$	3.3	$	4.5	$	4.5	$	204.5	$	4.5	$	423.7	$	645.0	$	645.0
Average interest rate (a)	4.0%		4.0%		4.0%		1.4%		4.0%		4.0%
Fixed-rate debt	$	0.1	$	0.1	$	0.2	$	0.2	$	0.2	$	117.2	118.0		118.5
Average interest rate	4.2%		4.2%		4.2%		4.2%		4.2%		4.7%
Total													$	763.0	$	763.5

(a) Based on rates in effect at September 30, 2016

Debt maturities and repayments occurring in 2016 are discussed under "FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS".

Long-term Debt Interest Rate Risk Sensitivity Analysis

Our estimate of market risk exposure is presented for our fixed-rate and variable-rate debt at September 30, 2016 for which an immediate adverse market movement causes a potential material impact on our financial condition, results of operations or the fair value of the debt. We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. As of September 30, 2016, 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 debt, along with the impact of a change of one percent in interest rates:

DPL	At September 30, 2016				One percent
	Principal		Fair		interest rate
$ in millions	Amount		Value		risk
Long-term debt
Variable-rate debt	$	770.0	$	770.0	$	7.7
Fixed-rate debt	1,170.6		$	1,199.4	12.0
Total	$	1,940.6	$	1,969.4	$	19.7

DP&L	At September 30, 2016				One percent
	Principal		Fair		interest rate
$ in millions	Amount		Value		risk
Long-term debt
Variable-rate debt	$	645.0	$	645.0	$	6.5
Fixed-rate debt	118.0		118.5		1.2
Total	$	763.0	$	763.5	$	7.7

DPL’s 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

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point in interest rates has on the fair value of DPL’s$1,199.4 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$770.0 million variable-rate long-term debt outstanding as of September 30, 2016.

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$118.5 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 an increase of one percentage point in the interest rate has on DP&L’s results of operations related to DP&L’s$645.0 million variable-rate long-term debt outstanding as of September 30, 2016.

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.

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 goodwill and intangible assets. Refer to our Form 10-K for the year ended December 31, 2015 for a complete listing of our critical accounting policies and estimates. There have been no material changes to these critical accounting policies and estimates.

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	ELECTRIC SALES AND CUSTOMERS (a)
	DPL (b)		DP&L (c)		DPLER (d)
	Three months ended		Three months ended		Three months ended
	September 30,		September 30,		September 30,
	2016	2015	2016	2015	2016	2015
Electric Sales (millions of kWh)	4,810	3,949	4,586	4,297	—	1,391
Billed electric customers (end of period)	517,607	515,372	517,607	515,372	—	128,405
	Nine months ended		Nine months ended		Nine months ended
	September 30,		September 30,		September 30,
	2016	2015	2016	2015	2016	2015
Electric Sales (millions of kWh)	12,753	11,312	12,242	12,735	—	4,762
Billed electric customers (end of period)	517,607	515,372	517,607	515,372	—	128,405

(a) For 2016, this table contains wholesale sales in PJM market and to other utilities.

(b) Electric sales excludes 400 million kWh and 1,668 million kWh relating to DPLER during the three and nine months ended September 30, 2015, respectively. Billed electric customers excludes DPLER customers outside of the DP&L service territory of 15,679 customers for the quarter ended September 30, 2015.

(c) Included within this column are 991 million kWh and 3,094 million kWh of power that DP&L sold to DPLER within the DP&L service territory for the three and nine months ended September 30, 2015, respectively.

(d) For DPLER, in 2015, this table includes all sales of DPLER, both within and outside of the DP&L service territory.

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 September 30, 2016, 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 September 30, 2016. 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. Management and our Board of Directors are committed to the continued improvement of DPL's overall system 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,

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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, 2015 and Forms10-Q for the quarters ended June 30, and March 31, 2016 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, 2015. As of September 30, 2016, there have been no material changes with respect to the risk factors disclosed in our Form 10-K. If any of the events described in our risk factors occur, it could have a material effect on our results of operations, financial condition and cash flows.

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

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

None

Item 3 – Defaults Upon Senior Securities

None

Item 4 – Mine Safety Disclosures

Not applicable.

Item 5 – Other Information

None

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Item 6 – Exhibits

DPL Inc.	DP&L	Exhibit Number	Exhibit	Location
X	X	4.1	Credit Agreement, dated August 24, 2016, among The Dayton Power and Light Company, the lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as administrative agent and collateral agent, Morgan Stanley Senior Funding, Inc., as a lender and BMO Capital Markets Corp., Fifth Third Securities, The Huntington National Bank, PNC Capital Markets LLC, RBC Capital Markets, LLC, Regions Capital Markets, a division of Regions Bank, and SunTrust Robinson Humphrey, Inc., as managing agents	Exhibit 4.1 to Report on Form 8-K filed on August 30, 2016 (File No. 1-02385)
X	X	4.2	Pledge and Security Agreement, dated as of August 24, 2016, between The Dayton Power and Light Company and JPMorgan Chase Bank, N.A., as collateral agent	Exhibit 4.2 to Report on Form 8-K filed on August 30, 2016 (File No. 1-02385)
X	X	4.3	Fiftieth Supplemental Indenture, between The Bank of New York Mellon, as Trustee, and The Dayton Power and Light Company	Exhibit 4.3 to Report on Form 8-K filed on August 30, 2016 (File No. 1-02385)
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:	November 3, 2016	/s/ Kenneth J. Zagzebski
		Kenneth J. Zagzebski
		President and Chief Executive Officer
		(principal executive officer)
	November 3, 2016	/s/ Craig L. Jackson
		Craig L. Jackson
		Chief Financial Officer
		(principal financial officer)
	November 3, 2016	/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:	November 3, 2016	/s/ Thomas A. Raga
		Thomas A. Raga
		President and Chief Executive Officer
		(principal executive officer)
	November 3, 2016	/s/ Craig L. Jackson
		Craig L. Jackson
		Chief Financial Officer
		(principal financial officer)
	November 3, 2016	/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: November 3, 2016

/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: November 3, 2016

/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: November 3, 2016

/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: November 3, 2016

/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 September 30, 2016, 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: November 3, 2016

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 September 30, 2016, 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: November 3, 2016

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 September 30, 2016, 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: November 3, 2016

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 September 30, 2016, 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: November 3, 2016

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	9 Months Ended
	Sep. 30, 2016	Nov. 03, 2016
Entity Registrant Name	DPL INC
Entity Central Index Key	0000787250
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
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	2016
Document Fiscal Period Focus	Q3
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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues	$ 389.3	$ 403.3	$ 1,081.6	$ 1,252.1
Cost of revenues:
Fuel	78.9	71.4	206.0	202.2
Purchased power	111.7	144.9	330.5	458.5
Total cost of revenues	190.6	216.3	536.5	660.7
Gross margin	198.7	187.0	545.1	591.4
Operating expenses:
Operation and maintenance	91.5	95.8	257.2	267.4
Depreciation and amortization	30.9	33.8	100.3	100.9
General taxes	21.6	21.7	64.2	66.7
Impairment of Long-Lived Assets Held-for-use	0.0	0.0	235.5	0.0
Other	(0.7)	0.2	(0.6)	0.4
Total operating expenses	143.3	151.5	656.6	435.4
Operating income / (loss)	55.4	35.5	(111.5)	156.0
Other income / (expense), net
Investment income	0.1	0.1	0.3	0.1
Interest expense	(27.0)	(28.9)	(79.3)	(90.3)
Charge for early retirement of debt	(0.5)	(2.1)	(3.1)	(2.1)
Other expense	(0.2)	(0.5)	(0.9)	(1.2)
Total other expense, net	(27.6)	(31.4)	(83.0)	(93.5)
Earnings / (loss) from continuing operations before income taxes	27.8	4.1	(194.5)	62.5
Income tax expense / (benefit) from continuing operations	12.7	(1.4)	(75.0)	15.4
Net income / (loss) from continuing operations	15.1	5.5	(119.5)	47.1
Income / (loss) from discontinued operations	0.0	4.9	(0.7)	10.1
Gain from disposal of discontinued operations	0.0	0.0	49.2	0.0
Income tax expense / (benefit) for discontinued operations	0.0	1.8	18.9	(1.8)
Discontinued operations	0.0	3.1	29.6	11.9
Net income / (loss)	15.1	8.6	(89.9)	59.0
THE DAYTON POWER AND LIGHT COMPANY [Member]
Revenues	368.4	389.2	1,031.3	1,202.6
Cost of revenues:
Fuel	71.0	69.0	189.5	188.9
Purchased power	110.0	142.5	328.0	452.3
Total cost of revenues	181.0	211.5	517.5	641.2
Gross margin	187.4	177.7	513.8	561.4
Operating expenses:
Operation and maintenance	85.5	93.5	248.0	261.6
Depreciation and amortization	24.1	34.6	95.2	103.5
General taxes	21.2	21.1	62.8	65.0
Impairment of Long-Lived Assets Held-for-use	0.0	0.0	857.1	0.0
Gain on termination of contract	0.0	0.0	(27.7)	0.0
Other	0.0	0.0	0.2	0.4
Total operating expenses	130.8	149.2	1,235.6	430.5
Operating income / (loss)	56.6	28.5	(721.8)	130.9
Other income / (expense), net
Investment income	0.1	0.0	0.3	0.2
Interest expense	(6.5)	(6.9)	(17.2)	(24.6)
Charge for early retirement of debt	(0.5)	(5.0)	(0.5)	(5.0)
Other expense	0.1	(0.3)	(0.2)	(0.6)
Total other expense, net	(6.8)	(12.2)	(17.6)	(30.0)
Earnings / (loss) from continuing operations before income taxes	49.8	16.3	(739.4)	100.9
Income tax expense / (benefit) from continuing operations	19.7	0.8	(271.6)	25.0
Net income / (loss)	30.1	15.5	(467.8)	75.9
Dividends on preferred stock	0.3	0.3	0.7	0.7
Income / (loss) attributable to common stock	$ 29.8	$ 15.2	$ (468.5)	$ 75.2

XML

Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Net income	$ 15.1	$ 8.6	$ (89.9)	$ 59.0
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax	0.1	(0.3)	0.2	(0.2)
Derivative activity:
Change in derivative fair value, net of income tax	9.5	7.8	22.4	9.6
Reclassification of earnings, net of income tax	(5.5)	(2.0)	(24.4)	(3.4)
Total change in fair value of derivatives	4.0	5.8	(2.0)	6.2
Pension and postretirement activity:
Reclassification to earnings, net of income tax	0.0	0.1	0.1	(0.1)
Other comprehensive income / (loss)	4.1	5.6	(1.7)	5.9
Net comprehensive income / (loss)	19.2	14.2	(91.6)	64.9
THE DAYTON POWER AND LIGHT COMPANY [Member]
Net income	30.1	15.5	(467.8)	75.9
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax	0.1	(0.3)	0.2	(0.3)
Reclassification to earnings, net of income tax	0.0	0.0	0.0	0.0
Total change in fair value of available-for-sale securities	0.1	(0.3)	0.2	(0.3)
Derivative activity:
Change in derivative fair value, net of income tax	9.5	7.8	22.5	9.6
Reclassification of earnings, net of income tax	(5.6)	(2.0)	(24.8)	(3.3)
Total change in fair value of derivatives	3.9	5.8	(2.3)	6.3
Pension and postretirement activity:
Reclassification to earnings, net of income tax	0.7	0.8	1.7	2.6
Total change in unfunded pension obligation	0.7	0.8	1.7	2.6
Other comprehensive income / (loss)	4.7	6.3	(0.4)	8.6
Net comprehensive income / (loss)	$ 34.8	$ 21.8	$ (468.2)	$ 84.5

XML

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities	$ 0.0	$ 0.1	$ (0.1)	$ 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	(5.2)	(4.4)	(12.3)	(5.4)
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	3.0	1.1	13.8	1.6
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity	0.0	0.0	(0.1)	(0.4)
THE DAYTON POWER AND LIGHT COMPANY [Member]
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities	0.0	0.1	(0.1)	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	5.2	(4.4)	(12.2)	(5.4)
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	3.0	1.2	13.5	1.9
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity	$ (0.4)	$ (0.6)	$ (1.6)	$ (1.6)

XML

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 121.8	$ 32.4
Restricted cash	11.6	92.7
Accounts receivable, net	134.9	120.9
Inventories	80.0	109.1
Taxes applicable to subsequent years	19.7	81.2
Regulatory assets, current	0.0	14.4
Other prepayments and current assets	37.7	44.5
Disposal Group, Including Discontinued Operation, Other Assets, Current	0.0	62.2
Total current assets	405.7	557.4
Property, plant & equipment:
Property, plant & equipment	2,701.2	2,909.0
Less: Accumulated depreciation and amortization	(479.6)	(432.3)
Property, plant and equipment, net of depreciation	2,221.6	2,476.7
Construction work in process	112.1	85.0
Total net property, plant & equipment	2,333.7	2,561.7
Other non-current assets:
Regulatory assets, non-current	186.9	179.9
Intangible assets, net of amortization	0.9	5.0
Other deferred assets	23.2	20.7
Total other non-current assets	211.0	205.6
Total assets	2,950.4	3,324.7
Current liabilities:
Current portion of long-term debt	79.2	572.8
Accounts payable	87.4	97.5
Accrued taxes	186.7	142.4
Accrued interest	35.5	21.4
Security deposits	14.6	15.2
Regulatory liabilities, current	44.7	24.4
Insurance and claims costs	5.9	5.9
Other current liabilities	76.1	54.5
Deposit, Sale of Business	0.0	75.5
Disposal Group, Including Discontinued Operation, Liabilities, Current	0.0	1.6
Total current liabilities	530.1	1,011.2
Non-current liabilities:
Long-term debt	1,834.8	1,420.5
Deferred taxes	463.1	568.7
Taxes payable	1.6	84.1
Regulatory liabilities, non-current	129.9	127.0
Pension, retiree and other benefits	80.5	87.1
Other deferred credits	87.5	88.3
Total non-current liabilities	2,597.4	2,375.7
Redeemable preferred stock of subsidiary	0.0	18.4
Commitments and contingencies
Common shareholder's equity:
Common stock	0.0	0.0
Other paid-in capital	2,232.8	2,237.7
Accumulated other comprehensive income	15.7	17.4
Retained earnings/ (deficit)	(2,425.6)	(2,335.7)
Total common shareholder's equity	(177.1)	(80.6)
Total liabilities and shareholder's equity	2,950.4	3,324.7
THE DAYTON POWER AND LIGHT COMPANY [Member]
Current assets:
Cash and cash equivalents	92.9	5.4
Restricted cash	11.6	44.8
Accounts receivable, net	136.3	119.5
Inventories	78.6	108.0
Taxes applicable to subsequent years	19.2	79.2
Regulatory assets, current	0.0	14.4
Other prepayments and current assets	36.7	46.3
Total current assets	375.3	417.6
Property, plant & equipment:
Property, plant & equipment	3,073.4	5,244.7
Less: Accumulated depreciation and amortization	(1,285.8)	(2,584.0)
Property, plant and equipment, net of depreciation	1,787.6	2,660.7
Construction work in process	89.9	78.0
Total net property, plant & equipment	1,877.5	2,738.7
Other non-current assets:
Regulatory assets, non-current	186.9	179.9
Intangible assets, net of amortization	0.9	5.0
Other deferred assets	20.2	18.4
Total other non-current assets	208.0	203.3
Total assets	2,460.8	3,359.6
Current liabilities:
Current portion of long-term debt	3.5	443.1
Short-term debt	0.0	35.0
Accounts payable	76.8	94.1
Accrued taxes	122.2	86.2
Accrued interest	1.0	4.1
Security deposits	14.6	15.1
Regulatory liabilities, current	44.7	24.4
Other current liabilities	75.6	51.0
Advance on contract termination	0.0	27.7
Total current liabilities	338.4	780.7
Non-current liabilities:
Long-term debt	745.0	313.6
Deferred taxes	314.4	631.2
Taxes payable	1.5	82.1
Regulatory liabilities, non-current	129.9	127.0
Pension, retiree and other benefits	80.5	87.1
Unamortized investment tax credit	18.3	20.0
Other deferred credits	82.1	82.3
Total non-current liabilities	1,371.7	1,343.3
Redeemable preferred stock of subsidiary	0.0	22.9
Commitments and contingencies
Common shareholder's equity:
Common stock	0.4	0.4
Other paid-in capital	810.6	803.7
Accumulated other comprehensive income	(29.1)	(28.7)
Retained earnings/ (deficit)	(31.2)	437.3
Total common shareholder's equity	750.7	1,212.7
Total liabilities and shareholder's equity	$ 2,460.8	$ 3,359.6

XML

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2016	Dec. 31, 2015
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	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash flows from operating activities:
Net income	$ (89.9)	$ 59.0
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Depreciation and amortization	100.3	104.1
Amortization of debt market value adjustments	0.1	(1.1)
Charge for early retirement of debt	3.1	2.1
Deferred income taxes	(101.4)	(20.5)
Impairment of Long-Lived Assets Held-for-use	235.5	0.0
Gain on sale of business	(49.2)	0.0
Changes in certain assets and liabilities:
Accounts receivable	23.6	48.8
Inventories	29.1	3.1
Prepaid taxes	0.2	(0.6)
Taxes applicable to subsequent years	61.5	58.2
Deferred regulatory costs, net	19.5	27.6
Accounts payable	(10.2)	(15.9)
Accrued taxes payable	(34.2)	(39.2)
Accrued interest payable	13.9	3.7
Security deposits	(0.6)	19.4
Pension, retiree and other benefits	(2.2)	1.0
Other	(0.5)	10.7
Net cash provided by operating activities	198.6	260.4
Cash flows from investing activities:
Capital expenditures	(109.8)	(93.5)
Proceeds from sale of business	75.5	1.3
Insurance proceeds	5.2	0.0
Purchase of intangible assets	(0.3)	(0.6)
Decrease in restricted cash	5.5	3.2
Other investing activities, net	0.8	0.4
Net cash used in investing activities	(23.1)	(89.2)
Cash flows from financing activities:
Payments of Deferred Finance Costs	(8.0)	(5.6)
Proceeds from Issuance of Long-term Debt	442.8	325.0
Retirement of long-term debt	(520.8)	(474.5)
Borrowings from revolving credit facilities	0.0	70.0
Repayment of borrowings from revolving credit facilities	0.0	(60.0)
Proceeds from (Payments for) Other Financing Activities	(0.1)	(0.1)
Net cash used in financing activities	(86.1)	(145.2)
Cash and cash equivalents:
Net change	89.4	26.0
Balance at beginning of period	32.4	17.0
Cash and cash equivalents at end of period	121.8	43.0
Supplemental cash flow information:
Interest paid, net of amounts capitalized	61.1	77.3
Income taxes paid / (refunded), net	0.3	0.8
Non-cash financing and investing activities:
Accruals for capital expenditures	15.9	12.6
THE DAYTON POWER AND LIGHT COMPANY [Member]
Cash flows from operating activities:
Net income	(467.8)	75.9
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Depreciation and amortization	95.2	103.5
Charge for early retirement of debt	0.5	5.0
Deferred income taxes	(314.2)	(14.2)
Impairment of Long-Lived Assets Held-for-use	857.1	0.0
Changes in certain assets and liabilities:
Accounts receivable	(11.0)	37.3
Inventories	29.4	3.0
Prepaid taxes	2.7	(0.4)
Taxes applicable to subsequent years	59.9	56.4
Deferred regulatory costs, net	19.5	27.6
Accounts payable	(13.5)	(20.0)
Accrued taxes payable	(43.2)	(29.1)
Accrued interest payable	(3.3)	(8.8)
Pension, retiree and other benefits	(2.2)	1.0
Other	11.3	10.5
Net cash provided by operating activities	220.4	247.7
Cash flows from investing activities:
Capital expenditures	(98.3)	(91.2)
Insurance proceeds	5.6	4.3
Purchase of intangible assets	(0.3)	(0.6)
Decrease in restricted cash	5.5	3.2
Other investing activities, net	0.9	0.4
Net cash used in investing activities	(86.6)	(83.9)
Cash flows from financing activities:
Payments of Deferred Finance Costs	(8.0)	(3.3)
Proceeds from Issuance of Long-term Debt	442.8	200.0
Retirement of long-term debt	(445.3)	(314.5)
Borrowings from revolving credit facilities	0.0	50.0
Repayment of borrowings from revolving credit facilities	0.0	(40.0)
Dividends paid on common stock to parent	0.0	(50.0)
Issuance of short-term debt - related party	5.0	0.0
Repayment of short-term debt - related party	(40.0)	0.0
Dividends paid on preferred stock	(0.7)	(0.7)
Proceeds from (Payments for) Other Financing Activities	(0.1)	0.0
Net cash used in financing activities	(46.3)	(158.5)
Cash and cash equivalents:
Net change	87.5	5.3
Balance at beginning of period	5.4	5.4
Cash and cash equivalents at end of period	92.9	10.7
Supplemental cash flow information:
Interest paid, net of amounts capitalized	16.3	26.8
Income Taxes Paid, Net	0.3	0.8
Non-cash financing and investing activities:
Accruals for capital expenditures	10.1	12.6
Subsidiary of Common Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Non-cash financing and investing activities:
Equity Settlement of Related Party Payable	$ 7.5	$ 0.0

XML

Overview and Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2016

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’sone reportable segment is the Utility segment, comprised of its DP&L subsidiary. DPLER, which was DPL's competitive retail segment, was sold January 1, 2016. See Note 12 – Business Segments for more information relating to these reportable segments. The terms “we,” “us,” “our” and “ours” are used to refer to DPL and its subsidiaries.

DPL is an indirectly wholly-owned subsidiary of AES.

DP&L 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, distribution and transmission retail services are still regulated. DP&L has the exclusive right to provide such distribution and transmission services to approximately 518,000 customers located in West Central Ohio. Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio. DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost. 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 1,171 people as of September 30, 2016, of which 1,163 were employed by DP&L. Approximately 62% 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 amortized cost, which was adjusted to fair value at the date of the Merger for DPL. 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, 2015.

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 September 30, 2016; our results of operations for the three and nine months ended September 30, 2016 and 2015 and our cash flows for the nine months ended September 30, 2016 and 2015. 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 nine months ended September 30, 2016 may not be indicative of our results that will be realized for the full year ending December 31, 2016.

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.

As a result of push down accounting, DPL’s Condensed Consolidated Statements of Operations subsequent to the Merger include depreciation of fixed assets based upon their fair value at the Merger date.

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 September 30, 2016 and 2015 were $14.4 million and $13.0 million, respectively. The amounts of such taxes collected for the nine months ended September 30, 2016 and 2015 were $38.9 million and $38.5 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
2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective.	January 1, 2016	Deferred financing costs related to lines-of-credit of approximately $3.1 million recorded within Other deferred assets were not reclassified.
2015-03, Interest - Imputation of Interest (Subtopic 835-30)	The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective.	January 1, 2016	Deferred financing costs of approximately $2.1 million previously classified within Other prepayments and current assets and $14.0 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective.	January 1, 2016	There were no changes to the consolidation conclusions.
New Accounting Standards Issued But Not Yet Effective
2016-17, Consolidation (Topic 810): Interest Held through Related Parties That Are under Common Control	This standard amends the evaluation of whether a reporting entity is the primary beneficiary of a VIE by amending how a reporting entity, that is a single decision maker of a VIE, treats indirect interests in that entity held through related parties that are under common control. Transition method: retrospectively.	January 1, 2017 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 method.	January 1, 2018 Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective method	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements, but do not anticipate a material impact.
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.
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: Various.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt Instruments	This standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.
2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships	The standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
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.
2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	The standard significantly revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. Also, it amends certain disclosure requirements associated with the fair value of financial instruments. Transition: cumulative effect in Retained Earnings as of adoption or prospectively for equity investments without readily determinable fair value.	January 1, 2018. Limited early adoption permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.
2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	The standard replaces the current lower of cost or market test with a lower of cost or net realizable value test. Transition method: prospectively.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2014-09, 2016-08, 2016-10, 2016-12 Revenue from Contracts with Customers (Topic 606)	The Revenue from Contracts with Customers standard provides a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing revenue recognition. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments to the standard provide further clarification on contract revenue recognition specifically related to the implementation of the principal versus agent evaluation, the identification of performance obligations, clarification on accounting for licenses of intellectual property, and allows for the election to account for shipping and handling activities performed after control of a good has been transferred to the customer as a fulfillment cost. Transition method: a full retrospective or modified retrospective approach.	January 1, 2018 (deferred by ASU No. 2015-14). Earlier application is permitted only as of January 1, 2017.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.

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, distribution and transmission retail services are still regulated. DP&L has the exclusive right to provide such distribution and transmission services to approximately 518,000 customers located in West Central Ohio. Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio. DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost. 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’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 1,163 people as of September 30, 2016. Approximately 62% 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, peaking electric generating facilities and numerous transmission facilities, all of which are included in the financial statements at amortized cost. 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, 2015.

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 September 30, 2016; our results of operations for the three and nine months ended September 30, 2016 and 2015 and our cash flows for the nine months ended September 30, 2016 and 2015. 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 nine months ended September 30, 2016 may not be indicative of our results that will be realized for the full year ending December 31, 2016.

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 September 30, 2016 and 2015 were $14.4 million and $13.0 million, respectively. The amounts of such taxes collected for the nine months ended September 30, 2016 and 2015 were $38.9 million and $38.5 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
2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective.	January 1, 2016	Deferred financing costs related to lines-of-credit of approximately $0.7 million recorded within Other deferred assets were not reclassified.
2015-03, Interest - Imputation of Interest (Subtopic 835-30)	The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective.	January 1, 2016	Deferred financing costs of approximately $1.8 million previously classified within Other prepayments and current assets and $4.5 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities.
2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective.	January 1, 2016	There were no changes to the consolidation conclusions.
New Accounting Standards Issued But Not Yet Effective
2016-17, Consolidation (Topic 810): Interest Held through Related Parties That Are under Common Control	This standard amends the evaluation of whether a reporting entity is the primary beneficiary of a VIE by amending how a reporting entity, that is a single decision maker of a VIE, treats indirect interests in that entity held through related parties that are under common control. Transition method: retrospectively.	January 1, 2017 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 method.	January 1, 2018 Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective method	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements but do not anticipate a material impact.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	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.
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: Various.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt Instruments	This standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements.
2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships	The standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact 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.
2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	The standard significantly revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. Also, it amends certain disclosure requirements associated with the fair value of financial instruments. Transition: cumulative effect in Retained Earnings as of adoption or prospectively for equity investments without readily determinable fair value.	January 1, 2018. Limited early adoption permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements.
2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	The standard replaces the current lower of cost or market test with a lower of cost or net realizable value test. Transition method: prospectively.	January 1, 2017. 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
2014-09, 2016-08, 2016-10, 2016-12 Revenue from Contracts with Customers (Topic 606)	The Revenue from Contracts with Customers standard provides a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing revenue recognition. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments to the standard provide further clarification on contract revenue recognition specifically related to the implementation of the principal versus agent evaluation, the identification of performance obligations, clarification on accounting for licenses of intellectual property, and allows for the election to account for shipping and handling activities performed after control of a good has been transferred to the customer as a fulfillment cost. Transition method: a full retrospective or modified retrospective approach.	January 1, 2018 (deferred by ASU No. 2015-14). Earlier application is permitted only as of January 1, 2017.	We are currently evaluating the impact of adopting the standard on our financial statements.

XML

Supplemental Financial Information

9 Months Ended

Sep. 30, 2016

Supplemental Financial Information [Line Items]

Supplemental Financial Information

Supplemental Financial Information

Accounts receivable and Inventories are as follows at September 30, 2016 and December 31, 2015:

	September 30,			December 31,
$ in millions	2016			2015
Accounts receivable, net:
Unbilled revenue	$	29.4		$	43.3
Customer receivables	81.6			56.4
Amounts due from partners in jointly owned plants	12.8			16.0
Other	12.3			6.0
Provision for uncollectible accounts	(1.2		)	(0.8		)
Total accounts receivable, net	$	134.9		$	120.9
Inventories, at average cost:
Fuel and limestone	$	42.0		$	72.2
Plant materials and supplies	36.1			34.9
Other	1.9			2.0
Total inventories, at average cost	$	80.0		$	109.1

Accounts receivable of $31.0 million as of December 31, 2015 have been excluded from the above table as they have been reclassified as "Assets held for sale". See Note 13 – Discontinued Operations.

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and nine months ended September 30, 2016 and 2015 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statements of Operations	Three months ended						Nine months ended
		September 30,						September 30,
$ in millions		2016			2015			2016			2015
Gains and losses on cash flow hedges (Note 5):
	Interest expense	$	(0.2	)	$	(0.2	)	$	(0.7	)	$	(0.7	)
	Revenue	(9.3		)	(3.8		)	(46.6		)	(7.0		)
	Purchased power	1.0			0.9			9.1			2.7
	Total before income taxes	(8.5		)	(3.1		)	(38.2		)	(5.0		)
	Tax expense	3.0			1.1			13.8			1.6
	Net of income taxes	(5.5		)	(2.0		)	(24.4		)	(3.4		)
Amortization of defined benefit pension items (Note 8):
	Operation and maintenance	—			0.1			0.2			0.3
	Tax benefit	—			—			(0.1		)	(0.4		)
	Net of income taxes	—			0.1			0.1			(0.1		)
Total reclassifications for the period, net of income taxes		$	(5.5	)	$	(1.9	)	$	(24.3	)	$	(3.5	)

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months endedSeptember 30, 2016 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities		Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total
Balance January 1, 2016	$	0.4	$	26.7		$	(9.7	)	$	17.4
Other comprehensive income before reclassifications	0.2		22.4			—			22.6
Amounts reclassified from accumulated other comprehensive income / (loss)	—		(24.4		)	0.1			(24.3		)
Net current period other comprehensive income / (loss)	0.2		(2.0		)	0.1			(1.7		)
Balance September 30, 2016	$	0.6	$	24.7		$	(9.6	)	$	15.7

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 September 30, 2016 and December 31, 2015:

	September 30,			December 31,
$ in millions	2016			2015
Accounts receivable, net:
Unbilled revenue	$	29.4		$	43.3
Customer receivables	79.2			54.1
Amounts due from partners in jointly owned plants	12.8			16.0
Other	16.1			6.9
Provision for uncollectible accounts	(1.2		)	(0.8		)
Total accounts receivable, net	$	136.3		$	119.5
Inventories, at average cost:
Fuel and limestone	$	42.0		$	72.2
Plant materials and supplies	34.7			33.7
Other	1.9			2.1
Total inventories, at average cost	$	78.6		$	108.0

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and nine months ended September 30, 2016 and 2015 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Statements of Operations	Three months ended						Nine months ended
		September 30,						September 30,
$ in millions		2016			2015			2016			2015
Gains and losses on cash flow hedges (Note 5):
	Interest expense	$	(0.3	)	$	(0.3	)	$	(0.9	)	$	(0.9	)
	Revenue	(9.3		)	(3.8		)	(46.5		)	(7.0		)
	Purchased power	1.0			0.9			9.1			2.7
	Total before income taxes	(8.6		)	(3.2		)	(38.3		)	(5.2		)
	Tax expense	3.0			1.2			13.5			1.9
	Net of income taxes	(5.6		)	(2.0		)	(24.8		)	(3.3		)
Amortization of defined benefit pension items (Note 8):
	Operation and maintenance	1.1			1.4			3.3			4.2
	Tax benefit	(0.4		)	(0.6		)	(1.6		)	(1.6		)
	Net of income taxes	0.7			0.8			1.7			2.6
Total reclassifications for the period, net of income taxes		$	(4.9	)	$	(1.2	)	$	(23.1	)	$	(0.7	)

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months ended September 30, 2016 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities		Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total
Balance January 1, 2016	$	0.5	$	11.2		$	(40.4	)	$	(28.7	)
Other comprehensive income before reclassifications	0.2		22.5			—			22.7
Amounts reclassified from accumulated other comprehensive income / (loss)	—		(24.8		)	1.7			(23.1		)
Net current period other comprehensive income / (loss)	0.2		(2.3		)	1.7			(0.4		)
Balance September 30, 2016	$	0.7	$	8.9		$	(38.7	)	$	(29.1	)

XML

Regulatory Matters (Notes)

9 Months Ended

Sep. 30, 2016

Regulatory Matters [Abstract]

Schedule of Regulatory Assets and Liabilities [Text Block]

Regulatory Matters

Ohio law requires that all Ohio distribution utilities file either an ESP or MRO to establish rates for SSO service. Although it has been in effect since January 2014, on June 20, 2016, the Supreme Court of Ohio (Court) issued an opinion in the appeal of DP&L’s ESP 2, which had been approved by the PUCO for the years 2014-2016 and which, among other matters, permitted DP&L to collect a non-bypassable service stability rider equal to approximately $9.2 million per month for each of those years and required DP&L to legally separate its generation assets by January 1, 2017. Over the period of ESP 2, DP&L has used all available cash flow to fund, among other things, debt repayments and necessary investments to ensure reliability and system performance. No dividends have been paid by DPL to AES during this period. In the opinion, the Court stated briefly, without expanding upon the basis, that the PUCO’s approval of the ESP was reversed on the authority of one of the Court’s prior rulings in a separate case not involving DP&L. In view of that reversal, on July 27, 2016 DP&L filed a motion to withdraw ESP 2 and implement rates consistent with those in effect as a result of ESP 1.

On August 26, 2016, the PUCO granted DP&L's motion to withdraw ESP 2, thereby terminating ESP 2 and its provisions, terms and conditions, including the requirement for DP&L to legally separate its generation assets by January 1, 2017. While DP&L may legally separate its generation assets, it is continuing to evaluate its options and timing with respect to separation. Further, the PUCO granted DP&L's motion to implement the provisions, terms and conditions of ESP 1 until a subsequent standard service offer is authorized by the PUCO. Tariffs consistent with the PUCO's Finding and Order were filed and became effective September 1, 2016. The rates under ESP 1 will be in place until rates consistent with the outcome for DP&L’s pending ESP 3 filing are approved and effective. The impact of reverting to ESP 1 is expected to result in a revenue reduction of approximately $3.0 million per month compared to those collected under ESP 2.

On February 22, 2016, DP&L filed ESP 3 at the PUCO seeking an effective date of January 1, 2017. On September 23, 2016, DP&L withdrew part of its ESP 3 filing that requested a Reliable Electricity Rider (RER). On October 11, 2016, DP&L filed an amended application requesting to recover $145.0 million per year for seven years that supports the alternative to the RER, named the Distribution Modernization Rider. Also as part of its plan, DP&L recommends including renewable energy attributes as part of the product that is competitively bid, and seeks recovery of approximately $10.5 million of regulatory assets. The plan also proposes a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan establishes new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental costs DP&L may incur. An evidentiary hearing is scheduled to begin December 5, 2016. There can be no assurance that ESP 3 will be approved as filed or on a timely basis. If ESP 3 is not approved on a timely basis or if the final ESP 3 provides for terms that are more adverse than those submitted in DP&L's application, our results of operations, financial condition and cash flows could be materially impacted.

XML

Fair Value

9 Months Ended

Sep. 30, 2016

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 September 30, 2016 and December 31, 2015. Information about the fair value of our derivative instruments can be found in Note 5 – Derivative Instruments and Hedging Activities.

	September 30, 2016				December 31, 2015
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.3	$	0.3	$	0.2	$	0.2
Equity securities	2.4		3.4		3.0		3.8
Debt securities	4.5		4.5		4.4		4.3
Hedge funds	0.2		0.2		0.4		0.4
Real estate	0.3		0.3		0.3		0.3
Total Assets	$	7.7	$	8.7	$	8.3	$	9.0
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Debt	$	1,914.0	$	1,969.4	$	1,993.3	$	1,975.3

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 Debt, which is presented at amortized carrying value.

Debt

Unrealized gains or losses are not recognized in the financial statements as debt is presented at cost, net of unamortized premium or discount and deferred financing costs in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2016 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 $0.9 million ($0.6 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2016 and $0.7 million ($0.5 million after tax) of unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at December 31, 2015.

During the nine months endedSeptember 30, 2016, $2.3 million ($1.5 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 and Level 2 of the fair value hierarchy during the nine months ended September 30, 2016 and 2015.

The fair value of assets and liabilities at September 30, 2016 and December 31, 2015 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 September 30, 2016		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	—	$	—
Equity securities	3.4		—		3.4		—
Debt securities	4.5		—		4.5		—
Hedge funds	0.2		—		0.2		—
Real estate	0.3		—		0.3		—
Total Master Trust assets	8.7		0.3		8.4		—
Derivative Assets
FTRs	0.1		—		—		0.1
Forward power contracts	33.1		—		32.5		0.6
Total Derivative assets	33.2		—		32.5		0.7
Total Assets	$	41.9	$	0.3	$	40.9	$	0.7
Liabilities
Derivative Liabilities
Forward power contracts	30.9		—		25.9		5.0
Total Derivative liabilities	30.9		—		25.9		5.0
Debt	1,969.4		—		1,951.4		18.0
Total Liabilities	$	2,000.3	$	—	$	1,977.3	$	23.0

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at December 31, 2015		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.2	$	0.2	$	—	$	—
Equity securities	3.8		—		3.8		—
Debt securities	4.3		—		4.3		—
Hedge funds	0.4		—		0.4		—
Real estate	0.3		—		0.3		—
Total Master Trust assets	9.0		0.2		8.8		—
Derivative assets
Forward power contracts	30.5		—		30.5		—
FTRs	0.2		—		—		0.2
Total Derivative assets	30.7		—		30.5		0.2
Total Assets	$	39.7	$	0.2	$	39.3	$	0.2
Liabilities
Derivative liabilities
FTRs	$	0.5	$	—	$	—	0.5
Forward power contracts	27.0		—		23.9		3.1
Total Derivative liabilities	27.5		—		23.9		3.6
Debt	1,975.3		—		1,957.2		18.1
Total Liabilities	$	2,002.8	$	—	$	1,981.1	$	21.7

Our financial instruments are valued using the market approach in the following categories:

• Level 1 inputs are used for derivative contracts such as heating oil futures, 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 93% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Our 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 debt is not recorded at fair value.

Cash Equivalents

DPL had $90.1 million in money market funds included as part of cash and cash equivalents in its Consolidated Balance Sheet at September 30, 2016. The money market funds have quoted prices that are generally equivalent to par.

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. AROs for ash ponds, asbestos, river structures and underground storage tanks increased by a net amount of $3.0 million and increased by a net amount of $38.7 million during the nine months ended September 30, 2016 and 2015, respectively.

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 nine months endedSeptember 30, 2016 and their level within the fair value hierarchy (there were no impairments during the nine months ended September 30, 2015):

$ in millions	Nine months ended September 30, 2016
	Carrying		Fair Value						Gross
	Amount (b)		Level 1		Level 2		Level 3		Loss
Assets
Long-lived assets (a)
DP&L (Killen)	$	315.1	$	—	$	—	$	84.3	$	230.8
DP&L (peaking facilities)	$	9.9	$	—	$	—	$	5.2	$	4.7

(a)See Note 14 – Fixed-asset Impairment 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 nine months ended September 30, 2016:

$ in millions	Fair value		Valuation technique	Unobservable input	Range (weighted average)
Long-lived assets held and used:
DP&L (Killen)	$	84.3	Discounted cash flow	Annual revenue growth	-11% to 13% (2%)
				Annual pre-tax operating margin	-50% to 57% (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 September 30, 2016 and December 31, 2015. Information about the fair value of our derivative instruments can be found in Note 5 – Derivative Instruments and Hedging Activities.

	September 30, 2016				December 31, 2015
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.3	$	0.3	$	0.2	$	0.2
Equity securities	2.4		3.4		3.0		3.8
Debt securities	4.5		4.5		4.4		4.3
Hedge funds	0.2		0.2		0.4		0.4
Real estate	0.3		0.3		0.3		0.3
Total assets	$	7.7	$	8.7	$	8.3	$	9.0
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Debt	$	748.5	$	763.5	$	756.7	$	764.2

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 Debt, which is presented at amortized carrying value.

Debt

Unrealized gains or losses are not recognized in the financial statements as debt is presented at cost, net of unamortized premium or discount and deferred financing costs in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2016 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 $1.1 million ($0.7 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2016 and $0.8 million ($0.5 million after tax) in unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at December 31, 2015.

During the nine months endedSeptember 30, 2016, $2.3 million ($1.5 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 and Level 2 of the fair value hierarchy during the nine months ended September 30, 2016 and 2015.

The fair value of assets and liabilities at September 30, 2016 and December 31, 2015 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 September 30, 2016		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	—	$	—
Equity securities	3.4		—		3.4		—
Debt securities	4.5		—		4.5		—
Hedge funds	0.2		—		0.2		—
Real estate	0.3		—		0.3		—
Total Master Trust assets	8.7		0.3		8.4		—
Derivative assets
FTRs	0.1		—		—		0.1
Forward power contracts	33.2		—		32.6		0.6
Total derivative assets	33.3		—		32.6		0.7
Total assets	$	42.0	$	0.3	$	41.0	$	0.7
Liabilities
Derivative liabilities
Forward power contracts	$	31.0	$	—	$	26.0	$	5.0
Total derivative liabilities	31.0		—		26.0		5.0
Debt	763.5		—		745.5		18.0
Total liabilities	$	794.5	$	—	$	771.5	$	23.0

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at December 31, 2015		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.2	$	0.2	$	—	$	—
Equity securities	3.8		—		3.8		—
Debt securities	4.3		—		4.3		—
Hedge funds	0.4		—		0.4		—
Real estate	0.3		—		0.3		—
Total Master Trust assets	9.0		0.2		8.8		—
Derivative assets
FTRs	0.2		—		—		0.2
Forward power contracts	30.6		—		30.6		—
Total Derivative assets	30.8		—		30.6		0.2
Total assets	$	39.8	$	0.2	$	39.4	$	0.2
Liabilities
Derivative liabilities
FTRs	$	0.5	$	—	$	—	$	0.5
Forward power contracts	27.0		—		23.9		3.1
Total Derivative liabilities	27.5		—		23.9		3.6
Debt	764.2		—		746.1		18.1
Total liabilities	$	791.7	$	—	$	770.0	$	21.7

Our financial instruments are valued using the market approach in the following categories:

• Level 1 inputs are used for derivative contracts such as heating oil futures, 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 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 debt is not recorded at fair value.

Approximately 93% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Cash Equivalents

DP&L had $90.1 million in money market funds included as part of cash and cash equivalents in its Balance Sheet at September 30, 2016. The money market funds have quoted prices that are generally equivalent to par.

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. AROs for ash ponds, asbestos, river structures and underground storage tanks increased by a net amount of $3.0 million and increased by a net amount of $38.7 million during the nine months ended September 30, 2016 and 2015, respectively.

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 nine months endedSeptember 30, 2016 and their level within the fair value hierarchy (there were no impairments during the nine months ended September 30, 2015):

	Carrying		Fair Value						Gross
$ in millions	Amount (b)		Level 1		Level 2		Level 3		Loss
	Nine months ended September 30, 2016
Long-lived assets (a)
DP&L (Stuart)	$	456.4	$	—	$	—	$	164.4	$	292.0
DP&L (Killen)	$	330.5	$	—	$	—	$	84.3	$	246.2
DP&L (Zimmer)	$	429.9	$	—	$	—	$	111.0	$	318.9

(a)See Note 12 – Fixed-asset Impairment 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 nine months ended September 30, 2016:

$ in millions	Fair value		Valuation technique	Unobservable input	Range (weighted average)
Long-lived assets held and used:
DP&L (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%
DP&L (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 (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

9 Months Ended

Sep. 30, 2016

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 September 30, 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	2.8	—		2.8
Natural Gas Futures	Not designated	Dths	—	(20.0	)	(20.0	)
Forward power contracts	Designated	MWh	607.6	(10,699.9	)	(10,092.3	)
Forward power contracts	Not designated	MWh	2,866.9	(2,393.1	)	473.8

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

At December 31, 2015, 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	10.2	—		10.2
Forward power contracts	Designated	MWh	1,676.7	(7,795.8	)	(6,119.1	)
Forward power contracts	Not designated	MWh	5,049.9	(1,663.0	)	3,386.9

(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.

The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three and nine months endedSeptember 30, 2016 and 2015:

	Three months ended						Three months ended
	September 30, 2016						September 30, 2015
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	3.4		$	17.3		$	1.1		$	17.8
Net gains associated with current period hedging transactions	9.5			—			7.8			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.1		)	—			(0.1		)
Revenues	(6.0		)	—			(2.5		)	—
Purchased power	0.6			—			0.6			—
Ending accumulated derivative gains in AOCI	$	7.5		$	17.2		$	7.0		$	17.7
	Nine months ended						Nine months ended
	September 30, 2016						September 30, 2015
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	9.2		$	17.5		$	0.2		$	18.3
Net gains associated with current period hedging transactions	22.4			—			9.6			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.3		)	—			(0.6		)
Revenues	(30.0		)	—			(4.5		)	—
Purchased power	5.9			—			1.7			—
Ending accumulated derivative gains in AOCI	$	7.5		$	17.2		$	7.0		$	17.7
Portion expected to be reclassified to earnings in the next twelve months (a)	$	—		$	0.6
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	15			0

(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 sales 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, heating oil futures, natural gas, and certain forward power contracts are currently marked to market.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting and are recognized in the Condensed Consolidated Statements of Operations on an accrual basis.

Regulatory Assets and Liabilities

In accordance with regulatory accounting under GAAP, a cost or loss that is probable of recovery in future rates should be deferred as a regulatory asset and revenue or a gain that is probable of being returned to customers should be deferred as a regulatory liability. Therefore, a portion of the heating oil futures are assigned to the retail jurisdiction and deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made. Beginning January 1, 2016, we no longer assign any portion of the heating oil futures to our retail jurisdiction as all of our SSO retail sales are sourced through the competitive bid process.

Financial Statement Effect

The following tables present the amount and classification within the Condensed Consolidated Statements of Operations or Condensed Consolidated Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and nine months ended September 30, 2016 and 2015:

For the three months ended September 30, 2016
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	—		$	1.2		$	(0.3	)	$	0.9
Realized gain / (loss)	(0.1		)	(2.4		)	0.2			(2.3		)
Total	$	(0.1	)	$	(1.2	)	$	(0.1	)	$	(1.4	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(10.4	)	$	—		$	(10.4	)
Purchased power	(0.1		)	9.2			(0.1		)	9.0
Total	$	(0.1	)	$	(1.2	)	$	(0.1	)	$	(1.4	)

For the three months ended September 30, 2015
$ in millions	Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	0.1		$	0.1		$	(3.2	)	$	(3.0	)
Realized loss	(0.2		)	(0.1		)	(4.3		)	(4.6		)
Total	$	(0.1	)	$	—		$	(7.5	)	$	(7.6	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	—		$	3.5		$	3.5
Purchased power	—			—			(11.0		)	(11.0		)
Fuel	(0.1		)	—			—			$	(0.1	)
Total	$	(0.1	)	$	—		$	(7.5	)	$	(7.6	)

For the nine months ended September 30, 2016
$ in millions	FTRs			Power			Natural Gas		Total
Change in unrealized gain	$	0.4		$	2.3		$	—	$	2.7
Realized gain / (loss)	(0.4		)	(5.3		)	0.7		(5.0		)
Total	$	—		$	(3.0	)	$	0.7	$	(2.3	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(13.1	)	$	—	$	(13.1	)
Purchased power	—			10.1			0.7		10.8
Total	$	—		$	(3.0	)	$	0.7	$	(2.3	)

For the nine months ended September 30, 2015
$ in millions	Heating Oil			FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	0.4		$	0.2		$	(4.9	)	$	0.1		$	(4.2	)
Realized loss	(0.3		)	(0.1		)	(8.1		)	(0.1		)	(8.6		)
Total	$	0.1		$	0.1		$	(13.0	)	$	—		$	(12.8	)
Recorded on Balance Sheet: gain
Regulatory asset	$	0.1		$	—		$	—		$	—		$	0.1
Recorded in Income Statement: gain / (loss)
Revenue	—			—			8.9			—			8.9
Purchased power	—			0.1			(21.9		)	—			(21.8		)
Total	$	0.1		$	0.1		$	(13.0	)	$	—		$	(12.8	)

DPL has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements.

The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged. The following table presents the fair value and balance sheet classification of DPL’s derivative instruments at September 30, 2016:

Fair Values of Derivative Instruments
at September 30, 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	$	15.6	$	(13.3	)	$	—		$	2.3
Forward power contracts	Not designated	8.7		(7.6		)	—			1.1
FTRs	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	7.4		(1.1		)	—			6.3
Forward power contracts	Not designated	1.4		(0.7		)	—			0.7
Total assets		$	33.2	$	(22.7	)	$	—		$	10.5
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	16.1	$	(13.3	)	$	(2.7	)	$	0.1
Forward power contracts	Not designated	12.8		(7.6		)	(2.4		)	2.8
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	1.1		(1.1		)	—			—
Forward power contracts	Not designated	0.9		(0.7		)	—			0.2
Total liabilities		$	30.9	$	(22.7	)	$	(5.1	)	$	3.1

The following table presents the fair value and balance sheet classification of DPL’s derivative instruments at December 31, 2015:

Fair Values of Derivative Instruments
at December 31, 2015
				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	$	16.2	$	(7.1	)	$	—		$	9.1
Forward power contracts	Not designated	7.3		(5.5		)	—			1.8
FTRs	Not designated	0.2		(0.2		)	—			—
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	3.0		(2.4		)	—			0.6
Forward power contracts	Not designated	4.0		(2.7		)	—			1.3
Total assets		$	30.7	$	(17.9	)	$	—		$	12.8
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	7.1	$	(7.1	)	$	—		$	—
Forward power contracts	Not designated	14.5		(5.5		)	(8.0		)	1.0
FTRs	Not designated	0.5		(0.2		)	—			0.3
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	2.7		(2.4		)	—			0.3
Forward power contracts	Not designated	2.7		(2.7		)	—			—
Total liabilities		$	27.5	$	(17.9	)	$	(8.0	)	$	1.6

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 that threshold with one counterparty to the derivative instruments and they could request that we post collateral of $0.9 million at this time.

The aggregate fair value of DPL’s commodity derivative instruments that were in a MTM loss position at September 30, 2016 was $30.9 million. $5.1 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 $22.7 million. Since our debt is below investment grade, we could have to post collateral for the remaining $3.1 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 September 30, 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	2.8	—		2.8
Natural gas futures	Not designated	Dths	—	(20.0	)	(20.0	)
Forward power contracts	Designated	MWh	607.6	(10,699.9	)	(10,092.3	)
Forward power contracts	Not designated	MWh	2,866.9	(2,419.8	)	447.1

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

At December 31, 2015, 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	10.2	—		10.2
Forward power contracts	Designated	MWh	1,676.7	(7,795.8	)	(6,119.1	)
Forward power contracts	Not designated	MWh	5,049.9	(1,665.7	)	3,384.2

(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.

The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three and nine months endedSeptember 30, 2016 and 2015:

	Three months ended						Three months ended
	September 30, 2016						September 30, 2015
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	3.4		$	1.6		$	1.1		$	2.2
Net gains associated with current period hedging transactions	9.5			—			7.8			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.2		)	—			(0.1		)
Revenues	(6.0		)	—			(2.5		)	—
Purchased power	0.6			—			0.6			—
Ending accumulated derivative gains in AOCI	$	7.5		$	1.4		$	7.0		$	2.1
	Nine months ended						Nine months ended
	September 30, 2016						September 30, 2015
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	9.2		$	2.0		$	0.2		$	2.6
Net gains associated with current period hedging transactions	22.5			—			9.6			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.6		)	—			(0.5		)
Revenues	(30.1		)	—			(4.5		)	—
Purchased power	5.9			—			1.7			—
Ending accumulated derivative gains in AOCI	$	7.5		$	1.4		$	7.0		$	2.1
Portion expected to be reclassified to earnings in the next twelve months (a)	$	—		$	(0.7	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	15			0

(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 sales 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, heating oil futures, natural gas, and certain forward power contracts are currently marked to market.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting and are recognized in the Condensed Statements of Operations on an accrual basis.

Regulatory Assets and Liabilities

In accordance with regulatory accounting under GAAP, a cost or loss that is probable of recovery in future rates should be deferred as a regulatory asset and revenue or a gain that is probable of being returned to customers should be deferred as a regulatory liability. Therefore, a portion of the heating oil futures are assigned to the retail jurisdiction and deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made. Beginning January 1, 2016, we no longer assign any portion of the heating oil futures to our retail jurisdiction as all of our SSO retail sales are sourced through the competitive bid process.

Financial Statement Effect

The following tables present the amount and classification within the Condensed Statements of Operations or Condensed Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and nine months ended September 30, 2016 and 2015:

For the three months ended September 30, 2016
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	—		$	1.2		$	(0.3	)	$	0.9
Realized gain / (loss)	(0.1		)	(2.4		)	0.2			(2.3		)
Total	$	(0.1	)	$	(1.2	)	$	(0.1	)	$	(1.4	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(10.4	)	$	—		$	(10.4	)
Purchased power	(0.1		)	9.2			(0.1		)	9.0
Total	$	(0.1	)	$	(1.2	)	$	(0.1	)	$	(1.4	)

For the three months ended September 30, 2015
$ in millions	Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	0.1		$	0.1		$	(3.3	)	$	(3.1	)
Realized loss	(0.2		)	(0.1		)	(4.3		)	(4.6		)
Total	$	(0.1	)	$	—		$	(7.6	)	$	(7.7	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	—		$	3.4		$	3.4
Purchased power	—			—			(11.0		)	(11.0		)
Fuel	(0.1		)	—			—			(0.1		)
Total	$	(0.1	)	$	—		$	(7.6	)	$	(7.7	)

For the nine months ended September 30, 2016
$ in millions	FTRs			Power			Natural Gas		Total
Change in unrealized gain	$	0.4		$	2.3		$	—	$	2.7
Realized gain / (loss)	(0.4		)	(5.3		)	0.7		(5.0		)
Total	$	—		$	(3.0	)	$	0.7	$	(2.3	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(13.1	)	$	—	$	(13.1	)
Purchased power	—			10.1			0.7		10.8
Total	$	—		$	(3.0	)	$	0.7	$	(2.3	)

For the nine months ended September 30, 2015
$ in millions	Heating Oil			FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	0.4		$	0.2		$	(5.0	)	0.1			$	(4.3	)
Realized loss	(0.3		)	(0.1		)	(8.1		)	(0.1		)	(8.6		)
Total	$	0.1		$	0.1		$	(13.1	)	$	—		$	(12.9	)
Recorded in Balance Sheet:
Regulatory asset	$	0.1		$	—		$	—		$	—		$	0.1
Recorded in Income Statement: gain / (loss)
Purchased power	—			0.1			(21.9		)	—			(21.8		)
Fuel	—			—			8.8			—			8.8
Total	$	0.1		$	0.1		$	(13.1	)	$	—		$	(12.9	)

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. The following table presents the fair value and balance sheet classification of DP&L’s derivative instruments at September 30, 2016:

Fair Values of Derivative Instruments
at September 30, 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	$	15.6	$	(13.3	)	$	—		$	2.3
Forward power contracts	Not designated	8.8		(7.7		)	—			1.1
FTRs	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	7.4		(1.1		)	—			6.3
Forward power contracts	Not designated	1.4		(0.7		)	—			0.7
Total assets		$	33.3	$	(22.8	)	$	—		$	10.5
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	16.1	$	(13.3	)	$	(2.7	)	$	0.1
Forward power contracts	Not designated	12.9		(7.7		)	(2.4		)	2.8
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	1.1		(1.1		)	—			—
Forward power contracts	Not designated	0.9		(0.7		)	—			0.2
Total liabilities		$	31.0	$	(22.8	)	$	(5.1	)	$	3.1

The following table presents the fair value and balance sheet classification of DP&L’s derivative instruments at December 31, 2015:

Fair Values of Derivative Instruments
at December 31, 2015
				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	$	16.2	$	(7.1	)	$	—		$	9.1
Forward power contracts	Not designated	7.4		(5.5		)	—			1.9
FTRs	Not designated	0.2		(0.2		)	—			—
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	3.0		(2.4		)	—			0.6
Forward power contracts	Not designated	4.0		(2.7		)	—			1.3
Total assets		$	30.8	$	(17.9	)	$	—		$	12.9
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	7.1	$	(7.1	)	$	—		$	—
Forward power contracts	Not designated	14.5		(5.5		)	(8.0		)	1.0
FTRs	Not designated	0.5		(0.2		)	—			0.3
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	2.7		(2.4		)	—			0.3
Forward power contracts	Not designated	2.7		(2.7		)	—			—
Total liabilities		$	27.5	$	(17.9	)	$	(8.0	)	$	1.6

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 that threshold with one counterparty to the derivative instruments and they could request that we post collateral of $0.9 million at this time.

The aggregate fair value of DP&L’s commodity derivative instruments that were in a MTM loss position at September 30, 2016 was $31.0 million. $22.8 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 $5.1 million. Since our debt is below investment grade, we could have to post collateral for the remaining $3.1 million.

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Debt Obligations

9 Months Ended

Sep. 30, 2016

Debt Instrument [Line Items]

Debt Obligations

Debt

The following table provides a summary of DPL's outstanding debt.

	Interest		September 30,			December 31,
$ in millions	Rate	Maturity	2016			2015
Term loan - rate at 4.00% (a)		2022	$	445.0		$	—
First mortgage bonds	1.875%	2016	—			445.0
Pollution control series	4.8%	2036	100.0			100.0
Pollution control series - rates from 1.29% - 1.36% (a) and 1.13% - 1.17% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	18.0			18.1
Unamortized deferred financing costs			(5.6		)	(5.0		)
Unamortized debt discount and premiums, net			(11.1		)	(3.6		)
Total long-term debt at subsidiary			746.3			754.5
Bank term loan - rates from 2.67% - 2.77% (a) and 2.44% - 2.67% (b)		2020	125.0			125.0
Senior unsecured bonds	6.5%	2016	57.0			130.0
Senior unsecured bonds	6.75%	2019	200.0			200.0
Senior unsecured bonds	7.25%	2021	780.0			780.0
Note to DPL Capital Trust II (c)	8.125%	2031	15.6			15.6
Unamortized deferred financing costs			(9.3		)	(11.1		)
Unamortized debt discounts and premiums, net			(0.6		)	(0.7		)
Total long-term debt			1,914.0			1,993.3
Less: current portion			(79.2		)	(572.8		)
Total long-term debt			$	1,834.8		$	1,420.5

(a) Range of interest rates for the nine months endedSeptember 30, 2016.

(b) Range of interest rates for the year ended December 31, 2015.

(c) Note payable to related party. See Note 11 – Related Party Transactions for additional information.

Premiums or discounts recognized at the date of the Merger are amortized over the remaining life of the debt using the effective interest method.

Significant transactions

On February 5, 2016, $73.0 million of DPL's$130.0 million6.5% Senior Unsecured Notes Due 2016 were redeemed under the indenture's make-whole call provision, which allows for the bonds to be called prior to maturity with a make-whole payment as determined by discounting the bond's future cash flow by a similarly maturing U.S. Treasury bond's yield plus 50 basis points. On the call date, principal plus the make-whole payment due totaled $75.4 million, which was paid with cash on hand. On October 17, 2016, the remaining $57.0 million of the 6.5% Senior Unsecured Notes Due 2016 were redeemed at maturity with cash on hand.

On August 24, 2016, DP&L refinanced its $445.0 million of 1.875% First Mortgage Bonds due 2016, with a variable rate Term Loan B of $445.0 million maturing on August 24, 2022 and secured by a pledge of DP&L First Mortgage Bonds. The variable interest rate on the loan is calculated based on LIBOR plus a spread of 3.25%, with a LIBOR floor of 0.75%. Up to the maturity date but not starting until March 31, 2017, the loan amortizes 0.25% of the initial principal balance quarterly, and contains covenants and restrictions that are generally consistent with existing DP&L credit agreements.

Debt covenants and restrictions

DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement have two financial covenants. The first financial covenant measures Total Debt to Total Capitalization. The Total Debt to Total Capitalization ratio 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. The 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 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.

Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage.

THE DAYTON POWER AND LIGHT COMPANY [Member]

Debt Instrument [Line Items]

Debt Obligations

Debt

The following table provides a summary of DP&L's outstanding debt.

	Interest		September 30,			December 31,
$ in millions	Rate	Maturity	2016			2015
Term loan - rates from 4.00% - 4.00% (a)		2022	$	445.0		$	—
First mortgage bonds	1.875%	2016	—			445.0
Pollution control series	4.8%	2036	100.0			100.0
Pollution control series - rates from 1.29% - 1.36% (a) and 1.13% - 1.17% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	18.0			18.1
Unamortized deferred financing costs			(12.3		)	(6.2		)
Unamortized debt discount			(2.2		)	(0.2		)
Total long-term debt			748.5			756.7
Less: current portion			(3.5		)	(443.1		)
Total			$	745.0		$	313.6

(a)Range of interest rates for the nine months ended September 30, 2016.

(b)Range of interest rates for the year ended December 31, 2015.

Significant transactions

On August 24, 2016, DP&L refinanced its 1.875% First Mortgage Bonds Due 2016, with a variable rate Term Loan B of $445.0 million maturing on August 24, 2022 and secured by a pledge of DP&L First Mortgage Bonds. The variable interest rate on the loan is calculated based on LIBOR plus a spread of 3.25%, with a LIBOR floor of 0.75%. Up to the maturity date but not starting until March 31, 2017, the loan amortizes 0.25% of the initial principal balance quarterly, and contains covenants and restrictions that are generally consistent with existing DP&L credit agreements.

Debt covenants and restrictions

DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement have two financial covenants. The first measures Total Debt to Total Capitalization and is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.

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.

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Income Taxes

9 Months Ended

Sep. 30, 2016

Entity Information [Line Items]

Income Taxes

Income Taxes

The following table details the effective tax rates for the three and nine months ended September 30, 2016 and 2015.

	Three months ended		Nine months ended
	September 30,		September 30,
	2016	2015	2016	2015
DPL	45.7%	(34.1)%	38.6%	24.6%

Income tax expense for the nine months endedSeptember 30, 2016 and 2015 was calculated using the estimated annual effective income tax rates for 2016 and 2015 of 38.6% and 30.8%, respectively. For the three and nine months ended September 30, 2016 and 2015, management estimated 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.

For the three months ended September 30, 2016, DPL’s current period effective tax rate was greater than the estimated annual effective rate primarily due to a change in its uncertain tax positions. The increase in the annual effective rate compared to the same period in 2015 is primarily due to a forecasted pre-tax loss in the 2016 tax year.

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 nine months ended September 30, 2016 and 2015.

	Three months ended		Nine months ended
	September 30,		September 30,
	2016	2015	2016	2015
DP&L	39.6%	4.9%	36.7%	24.8%

Income tax expense for the three and nine months ended September 30, 2016 and 2015 was calculated using the estimated annual effective income tax rates for 2016 and 2015 of 36.7% and 29.0%, respectively. For the three and nine months ended September 30, 2016 and 2015 management estimated 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.

For the three months ended September 30, 2016, DP&L’s current period effective tax rate was greater than the estimated annual effective rate primarily due to a change in its uncertain tax positions and the deduction for the preferred stock dividends. The increase in the annual effective rate compared to the same period in 2015 is primarily due to a forecasted pre-tax loss in the 2016 tax year.

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Benefit Plans

9 Months Ended

Sep. 30, 2016

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 made during the nine months endedSeptember 30, 2016 and $5.0 million in employer contributions during the nine months endedSeptember 30, 2015.

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 amounts presented for postretirement include both health and life insurance. The pension and postretirement 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. See Note 11 – Related Party Transactions.

The net periodic benefit cost of the pension and postretirement benefit plans for the three and nine months ended September 30, 2016 and 2015 was:

Net Periodic Benefit Cost	Pension
	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
Service cost	$	1.4		$	1.7		$	4.2		$	5.3
Interest cost	3.7			4.4			11.1			13.0
Expected return on plan assets	(5.7		)	(5.7		)	(17.1		)	(17.0		)
Amortization of unrecognized:
Prior service cost	0.4			0.5			1.4			1.5
Actuarial loss	1.1			1.5			3.2			4.4
Net periodic benefit cost	$	0.9		$	2.4		$	2.8		$	7.2

Net Periodic Benefit Cost	Postretirement
	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
Service cost	$	—		$	0.1		$	0.1		$	0.1
Interest cost	0.2			0.2			0.4			0.5
Expected return on plan assets	(0.1		)	(0.1		)	(0.1		)	(0.1		)
Amortization of unrecognized:
Prior service cost	—			—			—			—
Actuarial gain	(0.1		)	(0.1		)	(0.4		)	(0.3		)
Net periodic benefit cost	$	—		$	0.1		$	—		$	0.2

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:

$ in millions	Pension		Postretirement
2016	$	6.2	$	0.4
2017	25.2		1.6
2018	25.8		1.5
2019	26.3		1.4
2020	26.7		1.4
2021 - 2025	134.8		5.7

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 made during the nine months endedSeptember 30, 2016 and $5.0 million in employer contributions during the nine months endedSeptember 30, 2015.

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 amounts presented for postretirement include both health and life insurance. The pension and postretirement 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. See Note 11 – Related Party Transactions.

The net periodic benefit cost of the pension and postretirement benefit plans for the three and nine months ended September 30, 2016 and 2015 was:

Net Periodic Benefit Cost	Pension
	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
Service cost	$	1.4		$	1.8		$	4.2		$	5.3
Interest cost	3.7			4.2			11.1			12.8
Expected return on plan assets	(5.7		)	(5.6		)	(17.1		)	(16.8		)
Amortization of unrecognized:
Prior service cost	0.8			0.9			2.3			2.5
Actuarial loss	1.8			2.4			5.4			7.2
Net periodic benefit cost	$	2.0		$	3.7		$	5.9		$	11.0

Net Periodic Benefit Cost	Postretirement
	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
Service cost	$	—		$	0.1		$	0.1		$	0.1
Interest cost	0.1			0.1			0.4			0.5
Expected return on plan assets	(0.1		)	(0.1		)	(0.1		)	(0.1		)
Amortization of unrecognized:
Prior service cost	0.1			0.1			0.1			0.1
Actuarial gain	(0.1		)	(0.2		)	(0.5		)	(0.5		)
Net periodic benefit cost	$	—		$	—		$	—		$	0.1

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:

$ in millions	Pension		Postretirement
2016	$	6.2	$	0.4
2017	25.2		1.6
2018	25.8		1.5
2019	26.3		1.4
2020	26.7		1.4
2021 - 2025	134.8		5.7

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Shareholder's Equity

9 Months Ended

Sep. 30, 2016

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 $0.01 par value common shares, of which 41,172,173 are outstanding at September 30, 2016. 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 not to have a negative retained earnings balance. After the fixed-asset impairment recorded during the second quarter of 2016 and as of September 30, 2016, DP&L's equity ratio was 50% 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.

On October 13, 2016 (the "Redemption Date"), DP&L redeemed all of its issued and outstanding preferred stock, consisting of the following series: Preferred Stock, 3.75% Series A, Cumulative (the “Series A Stock”); Preferred Stock, 3.75% Series B, Cumulative (the “Series B Stock”); and Preferred Stock, 3.90% Series C, Cumulative (the “Series C Stock” and, together with the Series A Stock and the Series B Stock, the “Preferred Stock”). On the Redemption Date, the Preferred Stock of each series was redeemed at the following prices as specified in DP&L’s Amended and Restated Articles of Incorporation,plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date: a price of $102.50 per share for the Series A Stock, a price of $103.00 per share for the Series B Stock, and a price of $101.00 per share for the Series C Stock. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, andall rights of the holders thereof as shareholders of DP&L, except the right to payment of the redemption price, ceased to exist.

As we issued the notice to redeem the preferred stock in the third quarter, the $23.5 million redemption value was included in Other Current Liabilities as of September 30, 2016. The difference between the carrying value of the Redeemable Preferred Stock and the redemption amount was charged to Other paid-in capital.

In addition, with DP&L preferred stock no longer outstanding, certain provisions in DP&L's Amended Articles of Incorporation which could limit the payment of cash dividends on any of its common stock, no longer apply.

Equity settlement of related party payable

DP&L settled a $7.5 million payable to DPL relating to income taxes. This payable balance was settled through equity and DPL's investment in DP&L was increased by $7.5 million as consideration for extinguishing the payable.

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Redeemable Preferred Stock of Subsidiary (Notes)

9 Months Ended

Sep. 30, 2016

Redeemable Preferred Stock of Subsidiary [Abstract]

Preferred Stock [Text Block]

Redeemable Preferred Stock of Subsidiary

On October 13, 2016 (the "Redemption Date"), DPL's subsidiary, DP&L, redeemed all of its issued and outstanding preferred stock, consisting of the following series: Preferred Stock, 3.75% Series A, Cumulative (the “Series A Stock”); Preferred Stock, 3.75% Series B, Cumulative (the “Series B Stock”); and Preferred Stock, 3.90% Series C, Cumulative (the “Series C Stock” and, together with the Series A Stock and the Series B Stock, the “Preferred Stock”). On the Redemption Date, the Preferred Stock of each series was redeemed at the following prices as specified in DP&L’s Amended and Restated Articles of Incorporation,plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date: a price of $102.50 per share for the Series A Stock, a price of $103.00 per share for the Series B Stock, and a price of $101.00 per share for the Series C Stock. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock is no longer outstanding, andall rights of the holders thereof as shareholders of DP&L, except the right to payment of the redemption price, ceased to exist.

As we issued the notice to redeem the preferred stock of DP&L in the third quarter, the $23.5 million redemption value was included in Other Current Liabilities as of September 30, 2016. The difference between the carrying value of the Redeemable Preferred Stock of Subsidiary and the redemption amount was charged to Other paid-in capital.

In addition, with DP&L preferred stock no longer outstanding, certain provisions in DP&L's Amended Articles of Incorporation which could limit the payment of cash dividends on any of its common stock, no longer apply.

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Contractual Obligations, Commercial Commitments and Contingencies

9 Months Ended

Sep. 30, 2016

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 these subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes.

At September 30, 2016, DPL had $16.6 million of guarantees on behalf of AES Ohio Generation to third parties for future financial or performance assurance under such agreements. The guarantee arrangements entered into by DPL with these third parties cover 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 $4.8 million and $0.5 million at September 30, 2016 and December 31, 2015, 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 owns a 4.9% equity ownership interest in OVEC, which is recorded using the cost method of accounting under GAAP. As of September 30, 2016, DP&L could be responsible for the repayment of 4.9%, or $74.9 million, of a $1,528.0 million debt obligation that has maturities from 2018 to 2040. This would only happen if OVEC defaulted on its debt payments. As of September 30, 2016, 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, 2015.

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 September 30, 2016, 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 and the Ohio EPA 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 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 owns a 4.9% equity ownership interest in OVEC, which is recorded using the cost method of accounting under GAAP. As of September 30, 2016, DP&L could be responsible for the repayment of 4.9%, or $74.9 million, of a $1,528.0 million debt obligation that has maturities from 2018 to 2040. This would only happen if OVEC defaulted on its debt payments. As of September 30, 2016, 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, 2015.

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 September 30, 2016, 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 and the Ohio EPA 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 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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Related Party Transactions

9 Months Ended

Sep. 30, 2016

Related Party Transaction [Line Items]

Related Party Transactions

Related Party Transactions

Service Company

Effective January 1, 2014, the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L. The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of other businesses.

Benefit plans

DPL has an agreement with AES or one of its affiliates to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. AES or its affiliate administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments.

The following table provides a summary of these transactions:

	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2016		2015		2016			2015
Transactions with the Service Company
Charges for services provided	$	9.7	$	8.9	$	32.8		$	28.5
Charges to the Service Company	$	1.1	$	1.1	$	3.4		$	5.1
Transactions with other AES affiliates:
Charges for health, welfare and benefit plans	$	3.9	$	4.3	$	5.6		$	12.5
Transactions with the Service Company:					At September 30, 2016			At December 31, 2015
Net payable to the Service Company					$	(1.4	)	$	(0.5	)

DPL Capital Trust II

DPL has a wholly-owned business trust, DPL Capital Trust II (the "Trust"), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.3 million and $0.3 million at September 30, 2016 and December 31, 2015, respectively, is included in Other deferred assets within Other non-current assets. DPL also has a note payable to the Trust amounting to $15.6 million and $15.6 million at September 30, 2016 and December 31, 2015, respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 6 – Debt for additional information.

In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust.

Income taxes

AES files federal and state income tax returns which consolidate DPL and its subsidiaries. Under a tax sharing agreement with AES, DPL is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. DPL had net payable balances of $97.0 million and $50.5 million at September 30, 2016 and December 31, 2015, respectively, which are recorded in Accounts receivable, net and Accrued taxes on the accompanying Balance Sheets on a gross basis.

THE DAYTON POWER AND LIGHT COMPANY [Member]

Related Party Transaction [Line Items]

Related Party Transactions

Related Party Transactions

Service Company

Effective January 1, 2014, the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L. The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of other businesses.

Benefit plans

DPL has an agreement with AES or one of its affiliates to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. AES or its affiliate administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments.

The following table provides a summary of these transactions:

	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
DP&L revenues:
Sales to DPLER (including MC Squared) (a)	$	—		$	66.0		$	—		$	245.0
DP&L Operation & Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(0.8	)	$	(0.8	)	$	(2.5	)	$	(2.4	)
Expense recoveries for services provided to DPLER (c)	$	—		$	0.6		$	—		$	1.8
Transactions with the Service Company:
Charges for services provided	$	9.4		$	7.6		$	29.2		$	24.3
Charges to the Service Company	$	1.1		$	1.1		$	3.3		$	5.0
Transactions with other AES affiliates:
Charges / (credits) for health, welfare and benefit plans	$	3.8		$	4.1		$	5.5		$	11.9
Balances with related parties:							At September 30, 2016			At December 31, 2015
Net payable to the Service Company							$	(1.4	)	$	(0.5	)
Short-term loan with DPL(d)							$	—		$	35.0
Receivable from MVIC (b)							$	4.3		$	2.8

(a) DP&L sold power to DPLER and MC Squared to satisfy the electric requirements of their retail customers. The revenue dollars associated with sales to DPLER and MC Squared are recorded as wholesale revenues in DP&L’s Financial Statements. These agreements were terminated upon the sale of DPLER on January 1, 2016.

(b) MVIC, a wholly-owned captive insurance subsidiary of DPL, provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC. DP&L received insurance proceeds from MVIC of $0.2 million and $0.5 million for the three months ended September 30, 2016 and 2015, respectively, and $0.4 million and $4.3 million for the nine months ended September 30, 2016 and 2015, respectively.

(c) Prior to the sale of DPLER, in the normal course of business DP&L incurred and recorded expenses on behalf of DPLER. Such expenses included but were not limited to employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. DP&L subsequently charged these expenses to DPLER at DP&L’s cost and credited the expense in which they were initially recorded.

(d) On December 31, 2015, DPL loaned $35.0 million to DP&L through an intercompany short-term loan at 2.67%.

Income taxes

AES files federal and state income tax returns which consolidate DPL and its subsidiaries, including DP&L. Under a tax sharing agreement with DPL, DP&L is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. DP&L had a net payable balance of $36.2 million at September 30, 2016 which is recorded in Accounts receivable, net and Accrued taxes on the accompanying Balance Sheets and a net receivable balance of $1.5 million at December 31, 2015 which is recorded in Accounts receivable, net and Accrued taxes on the accompanying Balance Sheets on a gross basis.

Gain on termination of contract

On January 1, 2016, DPL closed on the sale of DPLER. Also on January 1, 2016, DP&L terminated the contract it had with DPLER for the supply of electricity. The agreement terminating the contract was signed on December 28, 2015 and DP&L received $27.7 million of restricted cash on December 31, 2015 for the early termination of the contract. For the nine months ended September 30, 2016, this amount was recorded in Gain on termination of contract in the Condensed Statements of Operations and the cash received was included in Cash flows from operating activities in the Condensed Statements of Cash Flows.

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Business Segments

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Business Segments

Business Segments

At December 31, 2015, DPL had two segments consisting of the operations of two of its wholly-owned subsidiaries, DP&L (Utility segment)and DPLER (Competitive Retail segment which included DPLER's wholly-owned subsidiary, MC Squared). This is how we viewed our business and made decisions on how to allocate resources and evaluate performance.

The Competitive Retail segment, DPLER’s competitive retail electric service business, was sold on January 1, 2016 (see Note 13 – Discontinued Operations). DPL now operates through one segment, the Utility segment. Segment disclosures for 2015 have not been restated to show the competitive retail segment as a discontinued operation and therefore do not tie to the Condensed Consolidated Statement of Operations.

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and deliver electricity to residential, commercial, industrial and governmental customers. DP&L generates electricity at five coal-fired power plants and DP&L distributes power to approximately 518,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. Prior to the sale of DPLER, DP&L also sold electricity to DPLER and to other Ohio utilities. In 2016, all of DP&L's electricity for SSO customers was sourced through a competitive bid auction and DP&L's energy and capacity was primarily sold into the PJM wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.

The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L. Intercompany sales from DP&L to DPLER were based on fixed-price contracts for each customer; the price approximated market prices for wholesale power at the inception of each customer’s contract. These agreements were terminated in connection with the sale of DPLER on January 1, 2016.

Included in the “Other” column in the following tables are other businesses that do not meet the GAAP requirements for disclosure as reportable segments, certain corporate costs including interest expense on DPL’s debt, and adjustments related to purchase accounting from the Merger. Management evaluates segment performance based on gross margin. 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.

The following tables present financial information for each of DPL’s reportable business segments:

$ in millions	Utility Segment		Other			Adjustments and Eliminations			DPL Consolidated
For the three months ended September 30, 2016
Revenues from external customers	$	368.0	$	21.3		$	—		$	389.3
Intersegment revenues	0.4		2.0			(2.4		)	—
Total revenues	368.4		23.3			(2.4		)	389.3
Fuel	71.0		7.9			—			78.9
Purchased power	110.0		3.0			(1.3		)	111.7
Gross margin	$	187.4	$	12.4		$	(1.1	)	$	198.7
Depreciation and amortization	$	24.1	$	6.8		$	—		$	30.9
Interest expense	$	6.5	$	20.3		$	0.2		$	27.0
Income tax expense / (benefit)	$	19.7	$	(7.0	)	$	—		$	12.7
Net income / (loss)	$	30.1	$	(15.0	)	$	—		$	15.1
Cash capital expenditures	$	26.5	$	4.2		$	—		$	30.7

$ in millions	Utility Segment		Competitive Retail		Other			Adjustments and Eliminations			DPL Consolidated
For the three months ended September 30, 2015
Revenues from external customers	$	323.2	$	77.0	$	13.9		$	—		$	414.1
Intersegment revenues	66.0		—		1.5			(67.5		)	—
Total revenues	389.2		77.0		15.4			(67.5		)	414.1
Fuel	69.0		—		2.4			—			71.4
Purchased power	142.5		66.6		3.0			(66.7		)	145.4
Gross margin	$	177.7	$	10.4	$	10.0		$	(0.8	)	$	197.3
Depreciation and amortization	$	34.6	$	0.2	$	—		$	—		$	34.8
Interest expense	$	6.9	$	—	$	22.1		$	(0.1	)	$	28.9
Income tax expense / (benefit)	$	0.8	$	1.6	$	(2.1	)	$	—		$	0.3
Net income / (loss)	$	15.5	$	2.6	$	(9.5	)	$	—		$	8.6
Cash capital expenditures	$	27.9	$	0.3	$	0.5		$	—		$	28.7

$ in millions	Utility Segment			Other			Adjustments and Eliminations			DPL Consolidated
For the nine months ended September 30, 2016
Revenues from external customers	$	1,030.3		$	51.3		$	—		$	1,081.6
Intersegment revenues	1.0			4.2			(5.2		)	—
Total revenues	1,031.3			55.5			(5.2		)	1,081.6
Fuel	189.5			16.5			—			206.0
Purchased power	328.0			4.9			(2.4		)	330.5
Gross margin	$	513.8		$	34.1		$	(2.8	)	$	545.1
Depreciation and amortization	$	95.2		$	5.1		$	—		$	100.3
Fixed-asset impairment	$	857.1		$	(621.6	)	$	—		$	235.5
Interest expense	$	17.2		$	61.6		$	0.5		$	79.3
Income tax expense / (benefit)	$	(271.6	)	$	196.6		$	—		$	(75.0	)
Net income / (loss) from continuing operations	$	(467.8	)	$	348.3		$	—		$	(119.5	)
Discontinued operations, net of tax	$	—		$	29.6		$	—		$	29.6
Net income / (loss)	$	(467.8	)	$	377.9		$	—		$	(89.9	)
Cash capital expenditures	$	98.3		$	11.5		$	—		$	109.8
at September 30, 2016
Total assets	$	2,460.8		$	1,303.8		$	(814.2	)	$	2,950.4

$ in millions	Utility Segment		Competitive Retail			Other			Adjustments and Eliminations			DPL Consolidated
For the nine months ended September 30, 2015
Revenues from external customers	$	957.6	$	274.5		$	49.4		$	—		$	1,281.5
Intersegment revenues	245.0		—			4.4			(249.4		)	—
Total revenues	1,202.6		274.5			53.8			(249.4		)	1,281.5
Fuel	188.9		—			13.3			—			202.2
Purchased power	452.3		247.0			7.8			(246.9		)	460.2
Gross margin	$	561.4	$	27.5		$	32.7		$	(2.5	)	$	619.1
Depreciation and amortization	$	103.5	$	0.6		$	—		$	—		$	104.1
Interest expense	$	24.6	$	0.1		$	65.8		$	(0.2	)	$	90.3
Income tax expense / (benefit)	$	25.0	$	(2.6	)	$	(8.9	)	$	—		$	13.5
Net income / (loss)	$	75.9	$	10.9		$	(27.8	)	$	—		$	59.0
Cash capital expenditures	$	91.2	$	0.6		$	1.7		$	—		$	93.5
at December 31, 2015
Total assets	$	3,359.6	$	—		$	1,304.5		$	(1,339.4	)	$	3,324.7

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Discontinued Operations

9 Months Ended

Sep. 30, 2016

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 received $75.5 million of restricted cash on December 31, 2015 for the sale. This amount was shown as Restricted cash with the associated liability shown as "Deposit received on sale of DPLER" on the Balance Sheet as of December 31, 2015. Assets and liabilities related to DPLER were reclassified to "Assets held for sale" and "Liabilities held for sale" in the December 31, 2015 Condensed Consolidated Balance Sheet. 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 at December 31, 2015. Deferred taxes and intercompany balances were not reclassified to held for sale.

Operating activities related to DPLER have been reclassified to "Discontinued operations" in the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2015.

The following table summarizes the major categories of assets, liabilities at the dates indicated, and the revenues, cost of revenues, operating expenses and income tax of discontinued operations as of and for the periods indicated:

$ in millions									December 31, 2015
Accounts receivable, net									$	31.0
Property, plant & equipment, net									4.6
Intangible assets, net									24.6
Other assets									2.0
Total assets of the disposal group classified as held for sale in the balance sheets									$	62.2
Accounts payable									$	0.8
Other liabilities									0.8
Total liabilities of the disposal group classified as held for sale in the balance sheets									$	1.6
	Three months ended September 30,					Nine months ended September 30,
	2016		2015			2016			2015
Revenues	$	—	$	77.1		$	—		$	274.6
Cost of revenues	—		(66.5		)	—			(247.0		)
Operating expenses	—		(5.7		)	(0.7		)	(17.5		)
(Loss) / income from discontinued operations before income taxes	—		4.9			(0.7		)	10.1
Gain from disposal of discontinued operations	—		—			49.2			—
Income tax expense / (benefit)	—		1.8			18.9			(1.8		)
Income on discontinued operations	$	—	$	3.1		$	29.6		$	11.9

DPLER purchased its power from DP&L during 2015. Prior to DPLER being presented as a discontinued operation, this purchased power and DP&L's corresponding wholesale revenue would have been eliminated in consolidation.

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 and $28.4 million for the nine months endedSeptember 30, 2016 and 2015, respectively. Cash flows from investing activities for discontinued operations were $75.5 million and $0.7 million for the nine months endedSeptember 30, 2016 and 2015, respectively. All cash generated from discontinued operations was paid to DPL through dividends for all periods presented.

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Fixed-asset Impairment (Notes)

9 Months Ended

Sep. 30, 2016

Finite-Lived Intangible Assets [Line Items]

Asset Impairment Charges [Text Block]

Fixed-asset Impairment

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 an 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 Impairment

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 test and determined that the carrying amounts 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 expenses of $292.0 million, $246.2 million and $318.9 million for Stuart, Killen and Zimmer, respectively during the nine months ended September 30, 2016.

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Summary of Significant Accounting Policies (Policy)

9 Months Ended

Sep. 30, 2016

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’sone reportable segment is the Utility segment, comprised of its DP&L subsidiary. DPLER, which was DPL's competitive retail segment, was sold January 1, 2016. See Note 12 – Business Segments for more information relating to these reportable segments. The terms “we,” “us,” “our” and “ours” are used to refer to DPL and its subsidiaries.

DPL is an indirectly wholly-owned subsidiary of AES.

DP&L 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, distribution and transmission retail services are still regulated. DP&L has the exclusive right to provide such distribution and transmission services to approximately 518,000 customers located in West Central Ohio. Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio. DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost. 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 1,171 people as of September 30, 2016, of which 1,163 were employed by DP&L. Approximately 62% 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 amortized cost, which was adjusted to fair value at the date of the Merger for DPL. 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, 2015.

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 September 30, 2016; our results of operations for the three and nine months ended September 30, 2016 and 2015 and our cash flows for the nine months ended September 30, 2016 and 2015. 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 nine months ended September 30, 2016 may not be indicative of our results that will be realized for the full year ending December 31, 2016.

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.

As a result of push down accounting, DPL’s Condensed Consolidated Statements of Operations subsequent to the Merger include depreciation of fixed assets based upon their fair value at the Merger date.

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 September 30, 2016 and 2015 were $14.4 million and $13.0 million, respectively. The amounts of such taxes collected for the nine months ended September 30, 2016 and 2015 were $38.9 million and $38.5 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
2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective.	January 1, 2016	Deferred financing costs related to lines-of-credit of approximately $3.1 million recorded within Other deferred assets were not reclassified.
2015-03, Interest - Imputation of Interest (Subtopic 835-30)	The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective.	January 1, 2016	Deferred financing costs of approximately $2.1 million previously classified within Other prepayments and current assets and $14.0 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective.	January 1, 2016	There were no changes to the consolidation conclusions.
New Accounting Standards Issued But Not Yet Effective
2016-17, Consolidation (Topic 810): Interest Held through Related Parties That Are under Common Control	This standard amends the evaluation of whether a reporting entity is the primary beneficiary of a VIE by amending how a reporting entity, that is a single decision maker of a VIE, treats indirect interests in that entity held through related parties that are under common control. Transition method: retrospectively.	January 1, 2017 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 method.	January 1, 2018 Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective method	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements, but do not anticipate a material impact.
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.
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: Various.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt Instruments	This standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.
2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships	The standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
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.
2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	The standard significantly revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. Also, it amends certain disclosure requirements associated with the fair value of financial instruments. Transition: cumulative effect in Retained Earnings as of adoption or prospectively for equity investments without readily determinable fair value.	January 1, 2018. Limited early adoption permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.
2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	The standard replaces the current lower of cost or market test with a lower of cost or net realizable value test. Transition method: prospectively.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2014-09, 2016-08, 2016-10, 2016-12 Revenue from Contracts with Customers (Topic 606)	The Revenue from Contracts with Customers standard provides a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing revenue recognition. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments to the standard provide further clarification on contract revenue recognition specifically related to the implementation of the principal versus agent evaluation, the identification of performance obligations, clarification on accounting for licenses of intellectual property, and allows for the election to account for shipping and handling activities performed after control of a good has been transferred to the customer as a fulfillment cost. Transition method: a full retrospective or modified retrospective approach.	January 1, 2018 (deferred by ASU No. 2015-14). Earlier application is permitted only as of January 1, 2017.	We are currently evaluating the impact of adopting the standard on our 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, distribution and transmission retail services are still regulated. DP&L has the exclusive right to provide such distribution and transmission services to approximately 518,000 customers located in West Central Ohio. Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio. DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost. 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’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 1,163 people as of September 30, 2016. Approximately 62% 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, peaking electric generating facilities and numerous transmission facilities, all of which are included in the financial statements at amortized cost. 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, 2015.

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 September 30, 2016; our results of operations for the three and nine months ended September 30, 2016 and 2015 and our cash flows for the nine months ended September 30, 2016 and 2015. 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 nine months ended September 30, 2016 may not be indicative of our results that will be realized for the full year ending December 31, 2016.

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 September 30, 2016 and 2015 were $14.4 million and $13.0 million, respectively. The amounts of such taxes collected for the nine months ended September 30, 2016 and 2015 were $38.9 million and $38.5 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
2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective.	January 1, 2016	Deferred financing costs related to lines-of-credit of approximately $0.7 million recorded within Other deferred assets were not reclassified.
2015-03, Interest - Imputation of Interest (Subtopic 835-30)	The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective.	January 1, 2016	Deferred financing costs of approximately $1.8 million previously classified within Other prepayments and current assets and $4.5 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities.
2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective.	January 1, 2016	There were no changes to the consolidation conclusions.
New Accounting Standards Issued But Not Yet Effective
2016-17, Consolidation (Topic 810): Interest Held through Related Parties That Are under Common Control	This standard amends the evaluation of whether a reporting entity is the primary beneficiary of a VIE by amending how a reporting entity, that is a single decision maker of a VIE, treats indirect interests in that entity held through related parties that are under common control. Transition method: retrospectively.	January 1, 2017 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 method.	January 1, 2018 Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective method	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements but do not anticipate a material impact.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	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.
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: Various.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt Instruments	This standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements.
2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships	The standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact 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.
2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	The standard significantly revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. Also, it amends certain disclosure requirements associated with the fair value of financial instruments. Transition: cumulative effect in Retained Earnings as of adoption or prospectively for equity investments without readily determinable fair value.	January 1, 2018. Limited early adoption permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements.
2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	The standard replaces the current lower of cost or market test with a lower of cost or net realizable value test. Transition method: prospectively.	January 1, 2017. 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
2014-09, 2016-08, 2016-10, 2016-12 Revenue from Contracts with Customers (Topic 606)	The Revenue from Contracts with Customers standard provides a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing revenue recognition. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments to the standard provide further clarification on contract revenue recognition specifically related to the implementation of the principal versus agent evaluation, the identification of performance obligations, clarification on accounting for licenses of intellectual property, and allows for the election to account for shipping and handling activities performed after control of a good has been transferred to the customer as a fulfillment cost. Transition method: a full retrospective or modified retrospective approach.	January 1, 2018 (deferred by ASU No. 2015-14). Earlier application is permitted only as of January 1, 2017.	We are currently evaluating the impact of adopting the standard on our financial statements.

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2016

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
2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective.	January 1, 2016	Deferred financing costs related to lines-of-credit of approximately $3.1 million recorded within Other deferred assets were not reclassified.
2015-03, Interest - Imputation of Interest (Subtopic 835-30)	The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective.	January 1, 2016	Deferred financing costs of approximately $2.1 million previously classified within Other prepayments and current assets and $14.0 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective.	January 1, 2016	There were no changes to the consolidation conclusions.
New Accounting Standards Issued But Not Yet Effective
2016-17, Consolidation (Topic 810): Interest Held through Related Parties That Are under Common Control	This standard amends the evaluation of whether a reporting entity is the primary beneficiary of a VIE by amending how a reporting entity, that is a single decision maker of a VIE, treats indirect interests in that entity held through related parties that are under common control. Transition method: retrospectively.	January 1, 2017 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 method.	January 1, 2018 Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective method	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements, but do not anticipate a material impact.
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.
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: Various.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt Instruments	This standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.
2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships	The standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
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.
2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	The standard significantly revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. Also, it amends certain disclosure requirements associated with the fair value of financial instruments. Transition: cumulative effect in Retained Earnings as of adoption or prospectively for equity investments without readily determinable fair value.	January 1, 2018. Limited early adoption permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.
2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	The standard replaces the current lower of cost or market test with a lower of cost or net realizable value test. Transition method: prospectively.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2014-09, 2016-08, 2016-10, 2016-12 Revenue from Contracts with Customers (Topic 606)	The Revenue from Contracts with Customers standard provides a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing revenue recognition. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments to the standard provide further clarification on contract revenue recognition specifically related to the implementation of the principal versus agent evaluation, the identification of performance obligations, clarification on accounting for licenses of intellectual property, and allows for the election to account for shipping and handling activities performed after control of a good has been transferred to the customer as a fulfillment cost. Transition method: a full retrospective or modified retrospective approach.	January 1, 2018 (deferred by ASU No. 2015-14). Earlier application is permitted only as of January 1, 2017.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.

THE DAYTON POWER AND LIGHT COMPANY [Member]

Related Party Transaction [Line Items]

Schedule of 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
2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective.	January 1, 2016	Deferred financing costs related to lines-of-credit of approximately $0.7 million recorded within Other deferred assets were not reclassified.
2015-03, Interest - Imputation of Interest (Subtopic 835-30)	The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective.	January 1, 2016	Deferred financing costs of approximately $1.8 million previously classified within Other prepayments and current assets and $4.5 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities.
2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective.	January 1, 2016	There were no changes to the consolidation conclusions.
New Accounting Standards Issued But Not Yet Effective
2016-17, Consolidation (Topic 810): Interest Held through Related Parties That Are under Common Control	This standard amends the evaluation of whether a reporting entity is the primary beneficiary of a VIE by amending how a reporting entity, that is a single decision maker of a VIE, treats indirect interests in that entity held through related parties that are under common control. Transition method: retrospectively.	January 1, 2017 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 method.	January 1, 2018 Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective method	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements but do not anticipate a material impact.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	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.
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: Various.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt Instruments	This standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements.
2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships	The standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis.	January 1, 2017. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact 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.
2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	The standard significantly revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. Also, it amends certain disclosure requirements associated with the fair value of financial instruments. Transition: cumulative effect in Retained Earnings as of adoption or prospectively for equity investments without readily determinable fair value.	January 1, 2018. Limited early adoption permitted.	We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements.
2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	The standard replaces the current lower of cost or market test with a lower of cost or net realizable value test. Transition method: prospectively.	January 1, 2017. 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
2014-09, 2016-08, 2016-10, 2016-12 Revenue from Contracts with Customers (Topic 606)	The Revenue from Contracts with Customers standard provides a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing revenue recognition. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments to the standard provide further clarification on contract revenue recognition specifically related to the implementation of the principal versus agent evaluation, the identification of performance obligations, clarification on accounting for licenses of intellectual property, and allows for the election to account for shipping and handling activities performed after control of a good has been transferred to the customer as a fulfillment cost. Transition method: a full retrospective or modified retrospective approach.	January 1, 2018 (deferred by ASU No. 2015-14). Earlier application is permitted only as of January 1, 2017.	We are currently evaluating the impact of adopting the standard on our financial statements.

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Supplemental Financial Information (Tables)

9 Months Ended

Sep. 30, 2016

Supplemental Financial Information [Line Items]

Schedule of Supplemental Financial Information

Accounts receivable and Inventories are as follows at September 30, 2016 and December 31, 2015:

	September 30,			December 31,
$ in millions	2016			2015
Accounts receivable, net:
Unbilled revenue	$	29.4		$	43.3
Customer receivables	81.6			56.4
Amounts due from partners in jointly owned plants	12.8			16.0
Other	12.3			6.0
Provision for uncollectible accounts	(1.2		)	(0.8		)
Total accounts receivable, net	$	134.9		$	120.9
Inventories, at average cost:
Fuel and limestone	$	42.0		$	72.2
Plant materials and supplies	36.1			34.9
Other	1.9			2.0
Total inventories, at average cost	$	80.0		$	109.1

Reclassification out of Accumulated Other Comprehensive Income

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and nine months ended September 30, 2016 and 2015 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statements of Operations	Three months ended						Nine months ended
		September 30,						September 30,
$ in millions		2016			2015			2016			2015
Gains and losses on cash flow hedges (Note 5):
	Interest expense	$	(0.2	)	$	(0.2	)	$	(0.7	)	$	(0.7	)
	Revenue	(9.3		)	(3.8		)	(46.6		)	(7.0		)
	Purchased power	1.0			0.9			9.1			2.7
	Total before income taxes	(8.5		)	(3.1		)	(38.2		)	(5.0		)
	Tax expense	3.0			1.1			13.8			1.6
	Net of income taxes	(5.5		)	(2.0		)	(24.4		)	(3.4		)
Amortization of defined benefit pension items (Note 8):
	Operation and maintenance	—			0.1			0.2			0.3
	Tax benefit	—			—			(0.1		)	(0.4		)
	Net of income taxes	—			0.1			0.1			(0.1		)
Total reclassifications for the period, net of income taxes		$	(5.5	)	$	(1.9	)	$	(24.3	)	$	(3.5	)

Schedule of Accumulated Other Comprehensive Income (Loss)

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months endedSeptember 30, 2016 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities		Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total
Balance January 1, 2016	$	0.4	$	26.7		$	(9.7	)	$	17.4
Other comprehensive income before reclassifications	0.2		22.4			—			22.6
Amounts reclassified from accumulated other comprehensive income / (loss)	—		(24.4		)	0.1			(24.3		)
Net current period other comprehensive income / (loss)	0.2		(2.0		)	0.1			(1.7		)
Balance September 30, 2016	$	0.6	$	24.7		$	(9.6	)	$	15.7

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 September 30, 2016 and December 31, 2015:

	September 30,			December 31,
$ in millions	2016			2015
Accounts receivable, net:
Unbilled revenue	$	29.4		$	43.3
Customer receivables	79.2			54.1
Amounts due from partners in jointly owned plants	12.8			16.0
Other	16.1			6.9
Provision for uncollectible accounts	(1.2		)	(0.8		)
Total accounts receivable, net	$	136.3		$	119.5
Inventories, at average cost:
Fuel and limestone	$	42.0		$	72.2
Plant materials and supplies	34.7			33.7
Other	1.9			2.1
Total inventories, at average cost	$	78.6		$	108.0

Reclassification out of Accumulated Other Comprehensive Income

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and nine months ended September 30, 2016 and 2015 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Statements of Operations	Three months ended						Nine months ended
		September 30,						September 30,
$ in millions		2016			2015			2016			2015
Gains and losses on cash flow hedges (Note 5):
	Interest expense	$	(0.3	)	$	(0.3	)	$	(0.9	)	$	(0.9	)
	Revenue	(9.3		)	(3.8		)	(46.5		)	(7.0		)
	Purchased power	1.0			0.9			9.1			2.7
	Total before income taxes	(8.6		)	(3.2		)	(38.3		)	(5.2		)
	Tax expense	3.0			1.2			13.5			1.9
	Net of income taxes	(5.6		)	(2.0		)	(24.8		)	(3.3		)
Amortization of defined benefit pension items (Note 8):
	Operation and maintenance	1.1			1.4			3.3			4.2
	Tax benefit	(0.4		)	(0.6		)	(1.6		)	(1.6		)
	Net of income taxes	0.7			0.8			1.7			2.6
Total reclassifications for the period, net of income taxes		$	(4.9	)	$	(1.2	)	$	(23.1	)	$	(0.7	)

Schedule of Accumulated Other Comprehensive Income (Loss)

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months ended September 30, 2016 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities		Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total
Balance January 1, 2016	$	0.5	$	11.2		$	(40.4	)	$	(28.7	)
Other comprehensive income before reclassifications	0.2		22.5			—			22.7
Amounts reclassified from accumulated other comprehensive income / (loss)	—		(24.8		)	1.7			(23.1		)
Net current period other comprehensive income / (loss)	0.2		(2.3		)	1.7			(0.4		)
Balance September 30, 2016	$	0.7	$	8.9		$	(38.7	)	$	(29.1	)

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Fair Value (Tables)

9 Months Ended

Sep. 30, 2016

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 September 30, 2016 and December 31, 2015. Information about the fair value of our derivative instruments can be found in Note 5 – Derivative Instruments and Hedging Activities.

	September 30, 2016				December 31, 2015
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.3	$	0.3	$	0.2	$	0.2
Equity securities	2.4		3.4		3.0		3.8
Debt securities	4.5		4.5		4.4		4.3
Hedge funds	0.2		0.2		0.4		0.4
Real estate	0.3		0.3		0.3		0.3
Total Assets	$	7.7	$	8.7	$	8.3	$	9.0
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Debt	$	1,914.0	$	1,969.4	$	1,993.3	$	1,975.3

Fair Value of Assets and Liabilities Measured on Recurring Basis

The fair value of assets and liabilities at September 30, 2016 and December 31, 2015 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 September 30, 2016		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	—	$	—
Equity securities	3.4		—		3.4		—
Debt securities	4.5		—		4.5		—
Hedge funds	0.2		—		0.2		—
Real estate	0.3		—		0.3		—
Total Master Trust assets	8.7		0.3		8.4		—
Derivative Assets
FTRs	0.1		—		—		0.1
Forward power contracts	33.1		—		32.5		0.6
Total Derivative assets	33.2		—		32.5		0.7
Total Assets	$	41.9	$	0.3	$	40.9	$	0.7
Liabilities
Derivative Liabilities
Forward power contracts	30.9		—		25.9		5.0
Total Derivative liabilities	30.9		—		25.9		5.0
Debt	1,969.4		—		1,951.4		18.0
Total Liabilities	$	2,000.3	$	—	$	1,977.3	$	23.0

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at December 31, 2015		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.2	$	0.2	$	—	$	—
Equity securities	3.8		—		3.8		—
Debt securities	4.3		—		4.3		—
Hedge funds	0.4		—		0.4		—
Real estate	0.3		—		0.3		—
Total Master Trust assets	9.0		0.2		8.8		—
Derivative assets
Forward power contracts	30.5		—		30.5		—
FTRs	0.2		—		—		0.2
Total Derivative assets	30.7		—		30.5		0.2
Total Assets	$	39.7	$	0.2	$	39.3	$	0.2
Liabilities
Derivative liabilities
FTRs	$	0.5	$	—	$	—	0.5
Forward power contracts	27.0		—		23.9		3.1
Total Derivative liabilities	27.5		—		23.9		3.6
Debt	1,975.3		—		1,957.2		18.1
Total Liabilities	$	2,002.8	$	—	$	1,981.1	$	21.7

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 nine months endedSeptember 30, 2016 and their level within the fair value hierarchy (there were no impairments during the nine months ended September 30, 2015):

$ in millions	Nine months ended September 30, 2016
	Carrying		Fair Value						Gross
	Amount (b)		Level 1		Level 2		Level 3		Loss
Assets
Long-lived assets (a)
DP&L (Killen)	$	315.1	$	—	$	—	$	84.3	$	230.8
DP&L (peaking facilities)	$	9.9	$	—	$	—	$	5.2	$	4.7

(a)See Note 14 – Fixed-asset Impairment 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 nine months ended September 30, 2016:

$ in millions	Fair value		Valuation technique	Unobservable input	Range (weighted average)
Long-lived assets held and used:
DP&L (Killen)	$	84.3	Discounted cash flow	Annual revenue growth	-11% to 13% (2%)
				Annual pre-tax operating margin	-50% to 57% (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 and Cost Of Non-Derivative Instruments

The following table presents the fair value, carrying value and cost of our non-derivative instruments at September 30, 2016 and December 31, 2015. Information about the fair value of our derivative instruments can be found in Note 5 – Derivative Instruments and Hedging Activities.

	September 30, 2016				December 31, 2015
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.3	$	0.3	$	0.2	$	0.2
Equity securities	2.4		3.4		3.0		3.8
Debt securities	4.5		4.5		4.4		4.3
Hedge funds	0.2		0.2		0.4		0.4
Real estate	0.3		0.3		0.3		0.3
Total assets	$	7.7	$	8.7	$	8.3	$	9.0
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Debt	$	748.5	$	763.5	$	756.7	$	764.2

Fair Value of Assets and Liabilities Measured on Recurring Basis

The fair value of assets and liabilities at September 30, 2016 and December 31, 2015 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 September 30, 2016		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	—	$	—
Equity securities	3.4		—		3.4		—
Debt securities	4.5		—		4.5		—
Hedge funds	0.2		—		0.2		—
Real estate	0.3		—		0.3		—
Total Master Trust assets	8.7		0.3		8.4		—
Derivative assets
FTRs	0.1		—		—		0.1
Forward power contracts	33.2		—		32.6		0.6
Total derivative assets	33.3		—		32.6		0.7
Total assets	$	42.0	$	0.3	$	41.0	$	0.7
Liabilities
Derivative liabilities
Forward power contracts	$	31.0	$	—	$	26.0	$	5.0
Total derivative liabilities	31.0		—		26.0		5.0
Debt	763.5		—		745.5		18.0
Total liabilities	$	794.5	$	—	$	771.5	$	23.0

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at December 31, 2015		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.2	$	0.2	$	—	$	—
Equity securities	3.8		—		3.8		—
Debt securities	4.3		—		4.3		—
Hedge funds	0.4		—		0.4		—
Real estate	0.3		—		0.3		—
Total Master Trust assets	9.0		0.2		8.8		—
Derivative assets
FTRs	0.2		—		—		0.2
Forward power contracts	30.6		—		30.6		—
Total Derivative assets	30.8		—		30.6		0.2
Total assets	$	39.8	$	0.2	$	39.4	$	0.2
Liabilities
Derivative liabilities
FTRs	$	0.5	$	—	$	—	$	0.5
Forward power contracts	27.0		—		23.9		3.1
Total Derivative liabilities	27.5		—		23.9		3.6
Debt	764.2		—		746.1		18.1
Total liabilities	$	791.7	$	—	$	770.0	$	21.7

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 nine months endedSeptember 30, 2016 and their level within the fair value hierarchy (there were no impairments during the nine months ended September 30, 2015):

	Carrying		Fair Value						Gross
$ in millions	Amount (b)		Level 1		Level 2		Level 3		Loss
	Nine months ended September 30, 2016
Long-lived assets (a)
DP&L (Stuart)	$	456.4	$	—	$	—	$	164.4	$	292.0
DP&L (Killen)	$	330.5	$	—	$	—	$	84.3	$	246.2
DP&L (Zimmer)	$	429.9	$	—	$	—	$	111.0	$	318.9

(a)See Note 12 – Fixed-asset Impairment 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 nine months ended September 30, 2016:

$ in millions	Fair value		Valuation technique	Unobservable input	Range (weighted average)
Long-lived assets held and used:
DP&L (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%
DP&L (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 (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%

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Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

At September 30, 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	2.8	—		2.8
Natural Gas Futures	Not designated	Dths	—	(20.0	)	(20.0	)
Forward power contracts	Designated	MWh	607.6	(10,699.9	)	(10,092.3	)
Forward power contracts	Not designated	MWh	2,866.9	(2,393.1	)	473.8

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

At December 31, 2015, 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	10.2	—		10.2
Forward power contracts	Designated	MWh	1,676.7	(7,795.8	)	(6,119.1	)
Forward power contracts	Not designated	MWh	5,049.9	(1,663.0	)	3,386.9

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 nine months endedSeptember 30, 2016 and 2015:

	Three months ended						Three months ended
	September 30, 2016						September 30, 2015
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	3.4		$	17.3		$	1.1		$	17.8
Net gains associated with current period hedging transactions	9.5			—			7.8			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.1		)	—			(0.1		)
Revenues	(6.0		)	—			(2.5		)	—
Purchased power	0.6			—			0.6			—
Ending accumulated derivative gains in AOCI	$	7.5		$	17.2		$	7.0		$	17.7
	Nine months ended						Nine months ended
	September 30, 2016						September 30, 2015
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	9.2		$	17.5		$	0.2		$	18.3
Net gains associated with current period hedging transactions	22.4			—			9.6			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.3		)	—			(0.6		)
Revenues	(30.0		)	—			(4.5		)	—
Purchased power	5.9			—			1.7			—
Ending accumulated derivative gains in AOCI	$	7.5		$	17.2		$	7.0		$	17.7
Portion expected to be reclassified to earnings in the next twelve months (a)	$	—		$	0.6
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	15			0

(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 or Condensed Consolidated Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and nine months ended September 30, 2016 and 2015:

For the three months ended September 30, 2016
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	—		$	1.2		$	(0.3	)	$	0.9
Realized gain / (loss)	(0.1		)	(2.4		)	0.2			(2.3		)
Total	$	(0.1	)	$	(1.2	)	$	(0.1	)	$	(1.4	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(10.4	)	$	—		$	(10.4	)
Purchased power	(0.1		)	9.2			(0.1		)	9.0
Total	$	(0.1	)	$	(1.2	)	$	(0.1	)	$	(1.4	)

For the three months ended September 30, 2015
$ in millions	Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	0.1		$	0.1		$	(3.2	)	$	(3.0	)
Realized loss	(0.2		)	(0.1		)	(4.3		)	(4.6		)
Total	$	(0.1	)	$	—		$	(7.5	)	$	(7.6	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	—		$	3.5		$	3.5
Purchased power	—			—			(11.0		)	(11.0		)
Fuel	(0.1		)	—			—			$	(0.1	)
Total	$	(0.1	)	$	—		$	(7.5	)	$	(7.6	)

For the nine months ended September 30, 2016
$ in millions	FTRs			Power			Natural Gas		Total
Change in unrealized gain	$	0.4		$	2.3		$	—	$	2.7
Realized gain / (loss)	(0.4		)	(5.3		)	0.7		(5.0		)
Total	$	—		$	(3.0	)	$	0.7	$	(2.3	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(13.1	)	$	—	$	(13.1	)
Purchased power	—			10.1			0.7		10.8
Total	$	—		$	(3.0	)	$	0.7	$	(2.3	)

For the nine months ended September 30, 2015
$ in millions	Heating Oil			FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	0.4		$	0.2		$	(4.9	)	$	0.1		$	(4.2	)
Realized loss	(0.3		)	(0.1		)	(8.1		)	(0.1		)	(8.6		)
Total	$	0.1		$	0.1		$	(13.0	)	$	—		$	(12.8	)
Recorded on Balance Sheet: gain
Regulatory asset	$	0.1		$	—		$	—		$	—		$	0.1
Recorded in Income Statement: gain / (loss)
Revenue	—			—			8.9			—			8.9
Purchased power	—			0.1			(21.9		)	—			(21.8		)
Total	$	0.1		$	0.1		$	(13.0	)	$	—		$	(12.8	)

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged. The following table presents the fair value and balance sheet classification of DPL’s derivative instruments at September 30, 2016:

Fair Values of Derivative Instruments
at September 30, 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	$	15.6	$	(13.3	)	$	—		$	2.3
Forward power contracts	Not designated	8.7		(7.6		)	—			1.1
FTRs	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	7.4		(1.1		)	—			6.3
Forward power contracts	Not designated	1.4		(0.7		)	—			0.7
Total assets		$	33.2	$	(22.7	)	$	—		$	10.5
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	16.1	$	(13.3	)	$	(2.7	)	$	0.1
Forward power contracts	Not designated	12.8		(7.6		)	(2.4		)	2.8
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	1.1		(1.1		)	—			—
Forward power contracts	Not designated	0.9		(0.7		)	—			0.2
Total liabilities		$	30.9	$	(22.7	)	$	(5.1	)	$	3.1

The following table presents the fair value and balance sheet classification of DPL’s derivative instruments at December 31, 2015:

Fair Values of Derivative Instruments
at December 31, 2015
				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	$	16.2	$	(7.1	)	$	—		$	9.1
Forward power contracts	Not designated	7.3		(5.5		)	—			1.8
FTRs	Not designated	0.2		(0.2		)	—			—
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	3.0		(2.4		)	—			0.6
Forward power contracts	Not designated	4.0		(2.7		)	—			1.3
Total assets		$	30.7	$	(17.9	)	$	—		$	12.8
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	7.1	$	(7.1	)	$	—		$	—
Forward power contracts	Not designated	14.5		(5.5		)	(8.0		)	1.0
FTRs	Not designated	0.5		(0.2		)	—			0.3
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	2.7		(2.4		)	—			0.3
Forward power contracts	Not designated	2.7		(2.7		)	—			—
Total liabilities		$	27.5	$	(17.9	)	$	(8.0	)	$	1.6

THE DAYTON POWER AND LIGHT COMPANY [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

At September 30, 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	2.8	—		2.8
Natural gas futures	Not designated	Dths	—	(20.0	)	(20.0	)
Forward power contracts	Designated	MWh	607.6	(10,699.9	)	(10,092.3	)
Forward power contracts	Not designated	MWh	2,866.9	(2,419.8	)	447.1

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

At December 31, 2015, 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	10.2	—		10.2
Forward power contracts	Designated	MWh	1,676.7	(7,795.8	)	(6,119.1	)
Forward power contracts	Not designated	MWh	5,049.9	(1,665.7	)	3,384.2

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 nine months endedSeptember 30, 2016 and 2015:

	Three months ended						Three months ended
	September 30, 2016						September 30, 2015
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	3.4		$	1.6		$	1.1		$	2.2
Net gains associated with current period hedging transactions	9.5			—			7.8			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.2		)	—			(0.1		)
Revenues	(6.0		)	—			(2.5		)	—
Purchased power	0.6			—			0.6			—
Ending accumulated derivative gains in AOCI	$	7.5		$	1.4		$	7.0		$	2.1
	Nine months ended						Nine months ended
	September 30, 2016						September 30, 2015
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	9.2		$	2.0		$	0.2		$	2.6
Net gains associated with current period hedging transactions	22.5			—			9.6			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.6		)	—			(0.5		)
Revenues	(30.1		)	—			(4.5		)	—
Purchased power	5.9			—			1.7			—
Ending accumulated derivative gains in AOCI	$	7.5		$	1.4		$	7.0		$	2.1
Portion expected to be reclassified to earnings in the next twelve months (a)	$	—		$	(0.7	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	15			0

(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 or Condensed Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and nine months ended September 30, 2016 and 2015:

For the three months ended September 30, 2016
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	—		$	1.2		$	(0.3	)	$	0.9
Realized gain / (loss)	(0.1		)	(2.4		)	0.2			(2.3		)
Total	$	(0.1	)	$	(1.2	)	$	(0.1	)	$	(1.4	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(10.4	)	$	—		$	(10.4	)
Purchased power	(0.1		)	9.2			(0.1		)	9.0
Total	$	(0.1	)	$	(1.2	)	$	(0.1	)	$	(1.4	)

For the three months ended September 30, 2015
$ in millions	Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	0.1		$	0.1		$	(3.3	)	$	(3.1	)
Realized loss	(0.2		)	(0.1		)	(4.3		)	(4.6		)
Total	$	(0.1	)	$	—		$	(7.6	)	$	(7.7	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	—		$	3.4		$	3.4
Purchased power	—			—			(11.0		)	(11.0		)
Fuel	(0.1		)	—			—			(0.1		)
Total	$	(0.1	)	$	—		$	(7.6	)	$	(7.7	)

For the nine months ended September 30, 2016
$ in millions	FTRs			Power			Natural Gas		Total
Change in unrealized gain	$	0.4		$	2.3		$	—	$	2.7
Realized gain / (loss)	(0.4		)	(5.3		)	0.7		(5.0		)
Total	$	—		$	(3.0	)	$	0.7	$	(2.3	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(13.1	)	$	—	$	(13.1	)
Purchased power	—			10.1			0.7		10.8
Total	$	—		$	(3.0	)	$	0.7	$	(2.3	)

For the nine months ended September 30, 2015
$ in millions	Heating Oil			FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	0.4		$	0.2		$	(5.0	)	0.1			$	(4.3	)
Realized loss	(0.3		)	(0.1		)	(8.1		)	(0.1		)	(8.6		)
Total	$	0.1		$	0.1		$	(13.1	)	$	—		$	(12.9	)
Recorded in Balance Sheet:
Regulatory asset	$	0.1		$	—		$	—		$	—		$	0.1
Recorded in Income Statement: gain / (loss)
Purchased power	—			0.1			(21.9		)	—			(21.8		)
Fuel	—			—			8.8			—			8.8
Total	$	0.1		$	0.1		$	(13.1	)	$	—		$	(12.9	)

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

DP&L’s derivative instruments at September 30, 2016:

Fair Values of Derivative Instruments
at September 30, 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	$	15.6	$	(13.3	)	$	—		$	2.3
Forward power contracts	Not designated	8.8		(7.7		)	—			1.1
FTRs	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	7.4		(1.1		)	—			6.3
Forward power contracts	Not designated	1.4		(0.7		)	—			0.7
Total assets		$	33.3	$	(22.8	)	$	—		$	10.5
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	16.1	$	(13.3	)	$	(2.7	)	$	0.1
Forward power contracts	Not designated	12.9		(7.7		)	(2.4		)	2.8
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	1.1		(1.1		)	—			—
Forward power contracts	Not designated	0.9		(0.7		)	—			0.2
Total liabilities		$	31.0	$	(22.8	)	$	(5.1	)	$	3.1

The following table presents the fair value and balance sheet classification of DP&L’s derivative instruments at December 31, 2015:

Fair Values of Derivative Instruments
at December 31, 2015
				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	$	16.2	$	(7.1	)	$	—		$	9.1
Forward power contracts	Not designated	7.4		(5.5		)	—			1.9
FTRs	Not designated	0.2		(0.2		)	—			—
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	3.0		(2.4		)	—			0.6
Forward power contracts	Not designated	4.0		(2.7		)	—			1.3
Total assets		$	30.8	$	(17.9	)	$	—		$	12.9
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	7.1	$	(7.1	)	$	—		$	—
Forward power contracts	Not designated	14.5		(5.5		)	(8.0		)	1.0
FTRs	Not designated	0.5		(0.2		)	—			0.3
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	2.7		(2.4		)	—			0.3
Forward power contracts	Not designated	2.7		(2.7		)	—			—
Total liabilities		$	27.5	$	(17.9	)	$	(8.0	)	$	1.6

XML

Debt (Tables)

9 Months Ended

Sep. 30, 2016

Debt Instrument [Line Items]

Long-term Debt

	Interest		September 30,			December 31,
$ in millions	Rate	Maturity	2016			2015
Term loan - rate at 4.00% (a)		2022	$	445.0		$	—
First mortgage bonds	1.875%	2016	—			445.0
Pollution control series	4.8%	2036	100.0			100.0
Pollution control series - rates from 1.29% - 1.36% (a) and 1.13% - 1.17% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	18.0			18.1
Unamortized deferred financing costs			(5.6		)	(5.0		)
Unamortized debt discount and premiums, net			(11.1		)	(3.6		)
Total long-term debt at subsidiary			746.3			754.5
Bank term loan - rates from 2.67% - 2.77% (a) and 2.44% - 2.67% (b)		2020	125.0			125.0
Senior unsecured bonds	6.5%	2016	57.0			130.0
Senior unsecured bonds	6.75%	2019	200.0			200.0
Senior unsecured bonds	7.25%	2021	780.0			780.0
Note to DPL Capital Trust II (c)	8.125%	2031	15.6			15.6
Unamortized deferred financing costs			(9.3		)	(11.1		)
Unamortized debt discounts and premiums, net			(0.6		)	(0.7		)
Total long-term debt			1,914.0			1,993.3
Less: current portion			(79.2		)	(572.8		)
Total long-term debt			$	1,834.8		$	1,420.5

THE DAYTON POWER AND LIGHT COMPANY [Member]

Debt Instrument [Line Items]

Long-term Debt

	Interest		September 30,			December 31,
$ in millions	Rate	Maturity	2016			2015
Term loan - rates from 4.00% - 4.00% (a)		2022	$	445.0		$	—
First mortgage bonds	1.875%	2016	—			445.0
Pollution control series	4.8%	2036	100.0			100.0
Pollution control series - rates from 1.29% - 1.36% (a) and 1.13% - 1.17% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	18.0			18.1
Unamortized deferred financing costs			(12.3		)	(6.2		)
Unamortized debt discount			(2.2		)	(0.2		)
Total long-term debt			748.5			756.7
Less: current portion			(3.5		)	(443.1		)
Total			$	745.0		$	313.6

XML

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2016

Entity Information [Line Items]

Schedule of Effective Income Tax Rates

The following table details the effective tax rates for the three and nine months ended September 30, 2016 and 2015.

	Three months ended		Nine months ended
	September 30,		September 30,
	2016	2015	2016	2015
DPL	45.7%	(34.1)%	38.6%	24.6%

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 nine months ended September 30, 2016 and 2015.

	Three months ended		Nine months ended
	September 30,		September 30,
	2016	2015	2016	2015
DP&L	39.6%	4.9%	36.7%	24.8%

XML

Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2016

Entity Information [Line Items]

Schedule of Net Periodic Benefit Cost / (Income)

The net periodic benefit cost of the pension and postretirement benefit plans for the three and nine months ended September 30, 2016 and 2015 was:

Net Periodic Benefit Cost	Pension
	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
Service cost	$	1.4		$	1.7		$	4.2		$	5.3
Interest cost	3.7			4.4			11.1			13.0
Expected return on plan assets	(5.7		)	(5.7		)	(17.1		)	(17.0		)
Amortization of unrecognized:
Prior service cost	0.4			0.5			1.4			1.5
Actuarial loss	1.1			1.5			3.2			4.4
Net periodic benefit cost	$	0.9		$	2.4		$	2.8		$	7.2

Net Periodic Benefit Cost	Postretirement
	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
Service cost	$	—		$	0.1		$	0.1		$	0.1
Interest cost	0.2			0.2			0.4			0.5
Expected return on plan assets	(0.1		)	(0.1		)	(0.1		)	(0.1		)
Amortization of unrecognized:
Prior service cost	—			—			—			—
Actuarial gain	(0.1		)	(0.1		)	(0.4		)	(0.3		)
Net periodic benefit cost	$	—		$	0.1		$	—		$	0.2

Estimated Future Benefit Payments and Medicare Part D Reimbursements

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:

$ in millions	Pension		Postretirement
2016	$	6.2	$	0.4
2017	25.2		1.6
2018	25.8		1.5
2019	26.3		1.4
2020	26.7		1.4
2021 - 2025	134.8		5.7

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 and postretirement benefit plans for the three and nine months ended September 30, 2016 and 2015 was:

Net Periodic Benefit Cost	Pension
	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
Service cost	$	1.4		$	1.8		$	4.2		$	5.3
Interest cost	3.7			4.2			11.1			12.8
Expected return on plan assets	(5.7		)	(5.6		)	(17.1		)	(16.8		)
Amortization of unrecognized:
Prior service cost	0.8			0.9			2.3			2.5
Actuarial loss	1.8			2.4			5.4			7.2
Net periodic benefit cost	$	2.0		$	3.7		$	5.9		$	11.0

Net Periodic Benefit Cost	Postretirement
	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
Service cost	$	—		$	0.1		$	0.1		$	0.1
Interest cost	0.1			0.1			0.4			0.5
Expected return on plan assets	(0.1		)	(0.1		)	(0.1		)	(0.1		)
Amortization of unrecognized:
Prior service cost	0.1			0.1			0.1			0.1
Actuarial gain	(0.1		)	(0.2		)	(0.5		)	(0.5		)
Net periodic benefit cost	$	—		$	—		$	—		$	0.1

Estimated Future Benefit Payments and Medicare Part D Reimbursements

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:

$ in millions	Pension		Postretirement
2016	$	6.2	$	0.4
2017	25.2		1.6
2018	25.8		1.5
2019	26.3		1.4
2020	26.7		1.4
2021 - 2025	134.8		5.7

XML

Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2016

Related Party Transaction [Line Items]

Schedule of Related Party Transactions

The following table provides a summary of these transactions:

	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2016		2015		2016			2015
Transactions with the Service Company
Charges for services provided	$	9.7	$	8.9	$	32.8		$	28.5
Charges to the Service Company	$	1.1	$	1.1	$	3.4		$	5.1
Transactions with other AES affiliates:
Charges for health, welfare and benefit plans	$	3.9	$	4.3	$	5.6		$	12.5
Transactions with the Service Company:					At September 30, 2016			At December 31, 2015
Net payable to the Service Company					$	(1.4	)	$	(0.5	)

THE DAYTON POWER AND LIGHT COMPANY [Member]

Related Party Transaction [Line Items]

Schedule of Related Party Transactions

The following table provides a summary of these transactions:

	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2016			2015			2016			2015
DP&L revenues:
Sales to DPLER (including MC Squared) (a)	$	—		$	66.0		$	—		$	245.0
DP&L Operation & Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(0.8	)	$	(0.8	)	$	(2.5	)	$	(2.4	)
Expense recoveries for services provided to DPLER (c)	$	—		$	0.6		$	—		$	1.8
Transactions with the Service Company:
Charges for services provided	$	9.4		$	7.6		$	29.2		$	24.3
Charges to the Service Company	$	1.1		$	1.1		$	3.3		$	5.0
Transactions with other AES affiliates:
Charges / (credits) for health, welfare and benefit plans	$	3.8		$	4.1		$	5.5		$	11.9
Balances with related parties:							At September 30, 2016			At December 31, 2015
Net payable to the Service Company							$	(1.4	)	$	(0.5	)
Short-term loan with DPL(d)							$	—		$	35.0
Receivable from MVIC (b)							$	4.3		$	2.8

(a) DP&L sold power to DPLER and MC Squared to satisfy the electric requirements of their retail customers. The revenue dollars associated with sales to DPLER and MC Squared are recorded as wholesale revenues in DP&L’s Financial Statements. These agreements were terminated upon the sale of DPLER on January 1, 2016.

(b) MVIC, a wholly-owned captive insurance subsidiary of DPL, provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC. DP&L received insurance proceeds from MVIC of $0.2 million and $0.5 million for the three months ended September 30, 2016 and 2015, respectively, and $0.4 million and $4.3 million for the nine months ended September 30, 2016 and 2015, respectively.

(c) Prior to the sale of DPLER, in the normal course of business DP&L incurred and recorded expenses on behalf of DPLER. Such expenses included but were not limited to employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. DP&L subsequently charged these expenses to DPLER at DP&L’s cost and credited the expense in which they were initially recorded.

(d) On December 31, 2015, DPL loaned $35.0 million to DP&L through an intercompany short-term loan at 2.67%.

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Business Segments (Tables)

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Financial Reporting for Reportable Business Segments

The following tables present financial information for each of DPL’s reportable business segments:

$ in millions	Utility Segment		Other			Adjustments and Eliminations			DPL Consolidated
For the three months ended September 30, 2016
Revenues from external customers	$	368.0	$	21.3		$	—		$	389.3
Intersegment revenues	0.4		2.0			(2.4		)	—
Total revenues	368.4		23.3			(2.4		)	389.3
Fuel	71.0		7.9			—			78.9
Purchased power	110.0		3.0			(1.3		)	111.7
Gross margin	$	187.4	$	12.4		$	(1.1	)	$	198.7
Depreciation and amortization	$	24.1	$	6.8		$	—		$	30.9
Interest expense	$	6.5	$	20.3		$	0.2		$	27.0
Income tax expense / (benefit)	$	19.7	$	(7.0	)	$	—		$	12.7
Net income / (loss)	$	30.1	$	(15.0	)	$	—		$	15.1
Cash capital expenditures	$	26.5	$	4.2		$	—		$	30.7

$ in millions	Utility Segment		Competitive Retail		Other			Adjustments and Eliminations			DPL Consolidated
For the three months ended September 30, 2015
Revenues from external customers	$	323.2	$	77.0	$	13.9		$	—		$	414.1
Intersegment revenues	66.0		—		1.5			(67.5		)	—
Total revenues	389.2		77.0		15.4			(67.5		)	414.1
Fuel	69.0		—		2.4			—			71.4
Purchased power	142.5		66.6		3.0			(66.7		)	145.4
Gross margin	$	177.7	$	10.4	$	10.0		$	(0.8	)	$	197.3
Depreciation and amortization	$	34.6	$	0.2	$	—		$	—		$	34.8
Interest expense	$	6.9	$	—	$	22.1		$	(0.1	)	$	28.9
Income tax expense / (benefit)	$	0.8	$	1.6	$	(2.1	)	$	—		$	0.3
Net income / (loss)	$	15.5	$	2.6	$	(9.5	)	$	—		$	8.6
Cash capital expenditures	$	27.9	$	0.3	$	0.5		$	—		$	28.7

$ in millions	Utility Segment			Other			Adjustments and Eliminations			DPL Consolidated
For the nine months ended September 30, 2016
Revenues from external customers	$	1,030.3		$	51.3		$	—		$	1,081.6
Intersegment revenues	1.0			4.2			(5.2		)	—
Total revenues	1,031.3			55.5			(5.2		)	1,081.6
Fuel	189.5			16.5			—			206.0
Purchased power	328.0			4.9			(2.4		)	330.5
Gross margin	$	513.8		$	34.1		$	(2.8	)	$	545.1
Depreciation and amortization	$	95.2		$	5.1		$	—		$	100.3
Fixed-asset impairment	$	857.1		$	(621.6	)	$	—		$	235.5
Interest expense	$	17.2		$	61.6		$	0.5		$	79.3
Income tax expense / (benefit)	$	(271.6	)	$	196.6		$	—		$	(75.0	)
Net income / (loss) from continuing operations	$	(467.8	)	$	348.3		$	—		$	(119.5	)
Discontinued operations, net of tax	$	—		$	29.6		$	—		$	29.6
Net income / (loss)	$	(467.8	)	$	377.9		$	—		$	(89.9	)
Cash capital expenditures	$	98.3		$	11.5		$	—		$	109.8
at September 30, 2016
Total assets	$	2,460.8		$	1,303.8		$	(814.2	)	$	2,950.4

$ in millions	Utility Segment		Competitive Retail			Other			Adjustments and Eliminations			DPL Consolidated
For the nine months ended September 30, 2015
Revenues from external customers	$	957.6	$	274.5		$	49.4		$	—		$	1,281.5
Intersegment revenues	245.0		—			4.4			(249.4		)	—
Total revenues	1,202.6		274.5			53.8			(249.4		)	1,281.5
Fuel	188.9		—			13.3			—			202.2
Purchased power	452.3		247.0			7.8			(246.9		)	460.2
Gross margin	$	561.4	$	27.5		$	32.7		$	(2.5	)	$	619.1
Depreciation and amortization	$	103.5	$	0.6		$	—		$	—		$	104.1
Interest expense	$	24.6	$	0.1		$	65.8		$	(0.2	)	$	90.3
Income tax expense / (benefit)	$	25.0	$	(2.6	)	$	(8.9	)	$	—		$	13.5
Net income / (loss)	$	75.9	$	10.9		$	(27.8	)	$	—		$	59.0
Cash capital expenditures	$	91.2	$	0.6		$	1.7		$	—		$	93.5
at December 31, 2015
Total assets	$	3,359.6	$	—		$	1,304.5		$	(1,339.4	)	$	3,324.7

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Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2016

Discontinued Operations and Disposal Groups [Abstract]

Summary of Balance Sheet and Profit and Loss Information for Discontinued Operations

The following table summarizes the major categories of assets, liabilities at the dates indicated, and the revenues, cost of revenues, operating expenses and income tax of discontinued operations as of and for the periods indicated:

$ in millions									December 31, 2015
Accounts receivable, net									$	31.0
Property, plant & equipment, net									4.6
Intangible assets, net									24.6
Other assets									2.0
Total assets of the disposal group classified as held for sale in the balance sheets									$	62.2
Accounts payable									$	0.8
Other liabilities									0.8
Total liabilities of the disposal group classified as held for sale in the balance sheets									$	1.6
	Three months ended September 30,					Nine months ended September 30,
	2016		2015			2016			2015
Revenues	$	—	$	77.1		$	—		$	274.6
Cost of revenues	—		(66.5		)	—			(247.0		)
Operating expenses	—		(5.7		)	(0.7		)	(17.5		)
(Loss) / income from discontinued operations before income taxes	—		4.9			(0.7		)	10.1
Gain from disposal of discontinued operations	—		—			49.2			—
Income tax expense / (benefit)	—		1.8			18.9			(1.8		)
Income on discontinued operations	$	—	$	3.1		$	29.6		$	11.9

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Summary of Significant Accounting Policies (Narrative) (Details) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2016	Sep. 30, 2016 USD ($) employee	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) mi² employee segment generating_facility customer	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Significant Accounting Policies [Line Items]
Number of reportable segments | segment				1
Entity number of employees | employee		1,171		1,171
Employees under a collective bargaining agreement which expires in October-2011				62.00%
Excise taxes collected		$ 14.4	$ 13.0	$ 38.9	$ 38.5
THE DAYTON POWER AND LIGHT COMPANY [Member]
Significant Accounting Policies [Line Items]
Approximate number of retail customers | customer				518,000
Service area, square miles | mi²				6,000
Entity number of employees | employee		1,163		1,163
Employees under a collective bargaining agreement which expires in October-2011				62.00%
Number of generating facilities | generating_facility				5
Excise taxes collected		$ 14.4	$ 13.0	$ 38.9	$ 38.5
Line of Credit [Member]
Significant Accounting Policies [Line Items]
Noncurrent portion of deferred finance costs						$ 3.1
Line of Credit [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Significant Accounting Policies [Line Items]
Noncurrent portion of deferred finance costs						0.7
Adjustments for New Accounting Pronouncement [Member]
Significant Accounting Policies [Line Items]
Current portion of deferred finance costs						2.1
Noncurrent portion of deferred finance costs						14.0
Adjustments for New Accounting Pronouncement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Significant Accounting Policies [Line Items]
Current portion of deferred finance costs						1.8
Noncurrent portion of deferred finance costs						$ 4.5
Year 2016 [Member]
Significant Accounting Policies [Line Items]
Electric generation through competitive bid	100.00%

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Supplemental Financial Information (Supplemental Financial Information) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Supplemental Financial Information [Line Items]
Accounts receivable, net		$ 31.0
Unbilled revenue	$ 29.4	43.3
Customer receivables	81.6	56.4
Amounts due from partners in jointly owned stations	12.8	16.0
Other	12.3	6.0
Provision for uncollectible accounts	(1.2)	(0.8)
Total accounts receivable, net	134.9	120.9
Fuel and limestone	42.0	72.2
Plant materials and supplies	36.1	34.9
Other	1.9	2.0
Total inventories, at average cost	80.0	109.1
THE DAYTON POWER AND LIGHT COMPANY [Member]
Supplemental Financial Information [Line Items]
Unbilled revenue	29.4	43.3
Customer receivables	79.2	54.1
Amounts due from partners in jointly owned stations	12.8	16.0
Other	16.1	6.9
Provision for uncollectible accounts	(1.2)	(0.8)
Total accounts receivable, net	136.3	119.5
Fuel and limestone	42.0	72.2
Plant materials and supplies	34.7	33.7
Other	1.9	2.1
Total inventories, at average cost	$ 78.6	$ 108.0

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Supplemental Financial Information (Reclassification out of ACOI) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Other income	$ (27.6)	$ (31.4)	$ (83.0)	$ (93.5)
Tax expense	(12.7)	1.4	75.0	(15.4)
Net income / (loss)	15.1	8.6	(89.9)	59.0
Interest expense	(27.0)	(28.9)	(79.3)	(90.3)
Revenue	389.3	403.3	1,081.6	1,252.1
Purchased power	(111.7)	(144.9)	(330.5)	(458.5)
Operating Expenses	(143.3)	(151.5)	(656.6)	(435.4)
THE DAYTON POWER AND LIGHT COMPANY [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Other income	(6.8)	(12.2)	(17.6)	(30.0)
Tax expense	(19.7)	(0.8)	271.6	(25.0)
Net income / (loss)	30.1	15.5	(467.8)	75.9
Interest expense	(6.5)	(6.9)	(17.2)	(24.6)
Revenue	368.4	389.2	1,031.3	1,202.6
Purchased power	(110.0)	(142.5)	(328.0)	(452.3)
Operating Expenses	(130.8)	(149.2)	(1,235.6)	(430.5)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Net income / (loss)	(5.5)	(1.9)	(24.3)	(3.5)
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)	(4.9)	(1.2)	(23.1)	(0.7)
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	3.0	1.1	13.8	1.6
Net income / (loss)	(5.5)	(2.0)	(24.4)	(3.4)
Interest expense	(0.2)	(0.2)	(0.7)	(0.7)
Revenue	(9.3)	(3.8)	(46.6)	(7.0)
Purchased power	1.0	0.9	9.1	2.7
Total before income taxes	(8.5)	(3.1)	(38.2)	(5.0)
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	3.0	1.2	13.5	1.9
Net income / (loss)	(5.6)	(2.0)	(24.8)	(3.3)
Interest expense	(0.3)	(0.3)	(0.9)	(0.9)
Revenue	(9.3)	(3.8)	(46.5)	(7.0)
Purchased power	1.0	0.9	9.1	2.7
Total before income taxes	(8.6)	(3.2)	(38.3)	(5.2)
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	(0.1)	(0.4)
Net income / (loss)	0.0	0.1	0.1	(0.1)
Operating Expenses	0.0	0.1	0.2	0.3
Amortization of defined benefit pension items [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Tax expense	(0.4)	(0.6)	(1.6)	(1.6)
Net income / (loss)	0.7	0.8	1.7	2.6
Operating Expenses	$ 1.1	$ 1.4	$ 3.3	$ 4.2

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Supplemental Financial Information (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period			$ 17.4
Other comprehensive income before reclassifications			22.6
Amounts reclassified from accumulated other comprehensive income / (loss)			(24.3)
Other comprehensive income / (loss)	$ 4.1	$ 5.6	(1.7)	$ 5.9
Balance, end of period	15.7		15.7
THE DAYTON POWER AND LIGHT COMPANY [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period			(28.7)
Other comprehensive income before reclassifications			22.7
Amounts reclassified from accumulated other comprehensive income / (loss)			(23.1)
Other comprehensive income / (loss)	4.7	$ 6.3	(0.4)	$ 8.6
Balance, end of period	(29.1)		(29.1)
Gains / (losses) on available-for-sale securities [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period			0.4
Other comprehensive income before reclassifications			0.2
Amounts reclassified from accumulated other comprehensive income / (loss)			0.0
Other comprehensive income / (loss)			0.2
Balance, end of period	0.6		0.6
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			0.5
Other comprehensive income before reclassifications			0.2
Amounts reclassified from accumulated other comprehensive income / (loss)			0.0
Other comprehensive income / (loss)			0.2
Balance, end of period	0.7		0.7
Gains / (losses) on cash flow hedges [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period			26.7
Other comprehensive income before reclassifications			22.4
Amounts reclassified from accumulated other comprehensive income / (loss)			(24.4)
Other comprehensive income / (loss)			(2.0)
Balance, end of period	24.7		24.7
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			11.2
Other comprehensive income before reclassifications			22.5
Amounts reclassified from accumulated other comprehensive income / (loss)			(24.8)
Other comprehensive income / (loss)			(2.3)
Balance, end of period	8.9		8.9
Change in unfunded pension obligation [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period			(9.7)
Other comprehensive income before reclassifications			0.0
Amounts reclassified from accumulated other comprehensive income / (loss)			0.1
Other comprehensive income / (loss)			0.1
Balance, end of period	(9.6)		(9.6)
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			(40.4)
Other comprehensive income before reclassifications			0.0
Amounts reclassified from accumulated other comprehensive income / (loss)			1.7
Other comprehensive income / (loss)			1.7
Balance, end of period	$ (38.7)		$ (38.7)

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Regulatory Matters (Details) - USD ($) $ in Millions	Oct. 11, 2016	Sep. 01, 2016	Jul. 27, 2016
Service Stability Rider			$ 9.2
Revenue Reduction Per Month From Reverting Back to ESP 1		$ 3.0
Subsidiaries [Member]
Service Stability Rider			$ 9.2
Revenue Reduction Per Month From Reverting Back to ESP 1		$ 3.0
Subsequent Event [Member]
Distribution Modernization Rider	$ 145.0
Regulatory Assets, Renewable Energy Recovery	10.5
Subsequent Event [Member] | Subsidiaries [Member]
Distribution Modernization Rider	145.0
Regulatory Assets, Renewable Energy Recovery	$ 10.5

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Fair Value (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Long-term debt, earliest maturities	2016
Long-term debt, latest maturities	2061
Unrealized gains in AOCI, before tax	$ 0.9
Unrealized Gains in AOCI, Net of Tax	0.6
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax			$ 0.7
Unrealized gains and immaterial unrealized losses in AOCI, after tax			0.5
Unrealized losses in AOCI, before tax			0.1
Unrealized losses in AOCI, net of tax			0.1
Realized gains on investments sold to facilitate the distribution of benefits	2.3
Realized gains on investments sold to facilitate the distribution of benefits, after tax	$ 1.5
Percent of inputs to the fair value of derivative instruments from quoted market prices (percent)	93.00%
Gross additions to our existing landfill and asbestos AROs	$ 3.0	$ 38.7
THE DAYTON POWER AND LIGHT COMPANY [Member]
Long-term debt, earliest maturities	2016
Long-term debt, latest maturities	2061
Unrealized gains in AOCI, before tax	$ 1.1
Unrealized Gains in AOCI, Net of Tax	0.7
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax			0.8
Unrealized gains and immaterial unrealized losses in AOCI, after tax			0.5
Unrealized losses in AOCI, before tax			0.1
Unrealized losses in AOCI, net of tax			$ 0.1
Realized gains on investments sold to facilitate the distribution of benefits	2.3
Realized gains on investments sold to facilitate the distribution of benefits, after tax	$ 1.5
Percent of inputs to the fair value of derivative instruments from quoted market prices (percent)	93.00%
Gross additions to our existing landfill and asbestos AROs	$ 3.0	$ 38.7

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Fair Value (Fair Value and Cost of Non-Derivative Instruments) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Realized gains on investments sold to facilitate the distribution of benefits, after tax	$ 1.5
Unrealized Gains in AOCI, Net of Tax	0.6
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax		$ 0.7
THE DAYTON POWER AND LIGHT COMPANY [Member]
Realized gains on investments sold to facilitate the distribution of benefits, after tax	1.5
Unrealized Gains in AOCI, Net of Tax	0.7
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax		0.8
Cost [Member]
Total Assets	7.7	8.3
Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Assets	7.7	8.3
Fair Value [Member]
Total Master Trust Assets, Fair Value	8.7	9.0
Total Assets	8.7	9.0
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	8.7	9.0
Total Assets	8.7	9.0
Money Market Funds [Member] | Cost [Member]
Total Master Trust Assets, Cost	0.3	0.2
Money Market Funds [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	0.3	0.2
Money Market Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.3	0.2
Money Market Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.3	0.2
Equity Securities [Member] | Cost [Member]
Total Master Trust Assets, Cost	2.4	3.0
Equity Securities [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	2.4	3.0
Equity Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	3.4	3.8
Equity Securities [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	3.4	3.8
Debt Securities [Member] | Cost [Member]
Total Master Trust Assets, Cost	4.5	4.4
Debt Securities [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	4.5	4.4
Debt Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	4.5	4.3
Debt Securities [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	4.5	4.3
Hedge Funds [Member] | Cost [Member]
Total Master Trust Assets, Cost	0.2	0.4
Hedge Funds [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	0.2	0.4
Hedge Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.2	0.4
Hedge Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.2	0.4
Real Estate Funds [Member] | Cost [Member]
Total Master Trust Assets, Cost	0.3	0.3
Real Estate Funds [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	0.3	0.3
Real Estate Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Real Estate Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Debt [Member] | Cost [Member]
Debt, Cost	1,914.0	1,993.3
Debt [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt, Cost	748.5	756.7
Debt [Member] | Fair Value [Member]
Debt, Fair Value	1,969.4	1,975.3
Debt [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt, Fair Value	$ 763.5	$ 764.2

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Fair Value (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Level 1 [Member]
Total Master Trust Assets, Fair Value	$ 0.3	$ 0.2
Total Derivative Assets	0.0	0.0
Total Assets	0.3	0.2
Total Derivative Liabilities	0.0	0.0
Total Liabilities	0.0	0.0
Level 1 [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets	0.0	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] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.3	0.2
Total Derivative Assets	0.0	0.0
Total Assets	0.3	0.2
Total Derivative Liabilities	0.0	0.0
Total Liabilities	0.0	0.0
Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets	0.0	0.0
Total Derivative Liabilities		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 2 [Member]
Total Master Trust Assets, Fair Value	8.4	8.8
Total Derivative Assets	32.5	30.5
Total Assets	40.9	39.3
Total Derivative Liabilities	25.9	23.9
Total Liabilities	1,977.3	1,981.1
Level 2 [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets	0.0	0.0
Total Derivative Liabilities		0.0
Level 2 [Member] | Forward Contract Power [Member]
Total Derivative Assets	32.5	30.5
Total Derivative Liabilities	25.9	23.9
Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	8.4	8.8
Total Derivative Assets	32.6	30.6
Total Assets	41.0	39.4
Total Derivative Liabilities	26.0	23.9
Total Liabilities	771.5	770.0
Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets	0.0	0.0
Total Derivative Liabilities		0.0
Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Total Derivative Assets	32.6	30.6
Total Derivative Liabilities	26.0	23.9
Level 3 [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Total Derivative Assets	0.7	0.2
Total Assets	0.7	0.2
Total Derivative Liabilities	5.0	3.6
Total Liabilities	23.0	21.7
Level 3 [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets	0.1	0.2
Total Derivative Liabilities		0.5
Level 3 [Member] | Forward Contract Power [Member]
Total Derivative Assets	0.6	0.0
Total Derivative Liabilities	5.0	3.1
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Total Derivative Assets	0.7	0.2
Total Assets	0.7	0.2
Total Derivative Liabilities	5.0	3.6
Total Liabilities	23.0	21.7
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets	0.1	0.2
Total Derivative Liabilities		0.5
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Total Derivative Assets	0.6	0.0
Total Derivative Liabilities	5.0	3.1
Fair Value [Member]
Total Master Trust Assets, Fair Value	8.7	9.0
Total Derivative Assets	33.2	30.7
Total Assets	41.9	39.7
Total Derivative Liabilities	30.9	27.5
Total Liabilities	2,000.3	2,002.8
Fair Value [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets	0.1	0.2
Total Derivative Liabilities		0.5
Fair Value [Member] | Forward Contract Power [Member]
Total Derivative Assets	33.1	30.5
Total Derivative Liabilities	30.9	27.0
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	8.7	9.0
Total Derivative Assets	33.3	30.8
Total Assets	42.0	39.8
Total Derivative Liabilities	31.0	27.5
Total Liabilities	794.5	791.7
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets	0.1	0.2
Total Derivative Liabilities		0.5
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Total Derivative Assets	33.2	30.6
Total Derivative Liabilities	31.0	27.0
Money Market Funds [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0.3	0.2
Money Market Funds [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.3	0.2
Money Market Funds [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Money Market Funds [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Money Market Funds [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Money Market Funds [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Money Market Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.3	0.2
Money Market Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.3	0.2
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	3.4	3.8
Equity Securities [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	3.4	3.8
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	3.4	3.8
Equity Securities [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	3.4	3.8
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	4.5	4.3
Debt Securities [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	4.5	4.3
Debt Securities [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Debt Securities [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Debt Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	4.5	4.3
Debt Securities [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	4.5	4.3
Hedge Funds [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Hedge Funds [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Hedge Funds [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	0.2	0.4
Hedge Funds [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.2	0.4
Hedge Funds [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Hedge Funds [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Hedge Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.2	0.4
Hedge Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.2	0.4
Real Estate Funds [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Real Estate Funds [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Real Estate Funds [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Real Estate Funds [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Real Estate Funds [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Real Estate Funds [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Real Estate Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Real Estate Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
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	1,951.4	1,957.2
Debt [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt	745.5	746.1
Debt [Member] | Level 3 [Member]
Debt	18.0	18.1
Debt [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt	18.0	18.1
Debt [Member] | Fair Value [Member]
Debt	1,969.4	1,975.3
Debt [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt	$ 763.5	$ 764.2

XML

Fair Value Cash Equivalents (Details) $ in Millions	Sep. 30, 2016 USD ($)
Money Market Funds, at Carrying Value	$ 90.1
Subsidiaries [Member]
Money Market Funds, at Carrying Value	$ 90.1

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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	$ 2,333.7		$ 2,333.7		$ 2,561.7
Impairment of Long-Lived Assets Held-for-use	0.0	$ 0.0	235.5	$ 0.0
Killen [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	315.1		315.1
Impairment of Long-Lived Assets Held-for-use			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
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
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	84.3		84.3
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
THE DAYTON POWER AND LIGHT COMPANY [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	1,877.5		1,877.5		$ 2,738.7
Impairment of Long-Lived Assets Held-for-use	0.0	$ 0.0	857.1	$ 0.0
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	456.4		456.4
Impairment of Long-Lived Assets Held-for-use			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
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
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	164.4		164.4
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	330.5		330.5
Impairment of Long-Lived Assets Held-for-use			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
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
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	$ 84.3		$ 84.3

XML

Derivative Instruments and Hedging Activities (Narrative) (Details) $ in Millions	Sep. 30, 2016 USD ($)
Additional Collateral, Aggregate Fair Value, OTC Commodity Derivatives	$ 0.9
Fair value of commodity derivative instruments	30.9
Collateral Already Posted, Aggregate Fair Value	5.1
Liability position offset by the asset position of counterparties with master netting agreements	22.7
Collateral if debt were to fall below investment grade	3.1
THE DAYTON POWER AND LIGHT COMPANY [Member]
Additional Collateral, Aggregate Fair Value, OTC Commodity Derivatives	0.9
Fair value of commodity derivative instruments	31.0
Collateral Already Posted, Aggregate Fair Value	22.8
Liability position offset by the asset position of counterparties with master netting agreements	5.1
Collateral if debt were to fall below investment grade	$ 3.1

XML

Derivative Instruments and Hedging Activities (Outstanding Derivative Instruments) (Details)	Sep. 30, 2016 MMBTU MWh	Dec. 31, 2015 MWh
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights	2,800	10,200
Sale of Units Derivative Instruments Financial Transmission Rights	0	0
Derivative, Nonmonetary Notional Amount MWh	2,800	10,200
Not Designated as Hedging Instrument [Member] | Natural Gas [Member]
Purchase of Units Derivative Instruments Natural Gas | MMBTU	0
Sale of Units Derivative Instruments Natural Gas | MMBTU	(20,000)
Derivative, Nonmonetary Notional Amount MWh | MMBTU	(20,000)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	2,866,900	5,049,900
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	(2,393,100)	(1,663,000)
Derivative, Nonmonetary Notional Amount MWh	473,800	3,386,900
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	2,800	10,200
Sale of Units Derivative Instruments Financial Transmission Rights	0	0
Derivative, Nonmonetary Notional Amount MWh	2,800	10,200
Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Purchase of Units Derivative Instruments Natural Gas | MMBTU	0
Sale of Units Derivative Instruments Natural Gas | MMBTU	(20,000)
Derivative, Nonmonetary Notional Amount MWh | MMBTU	(20,000)
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	2,866,900	5,049,900
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	(2,419,800)	(1,665,700)
Derivative, Nonmonetary Notional Amount MWh	447,100	3,384,200
Designated as Hedging Instrument [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	607,600	1,676,700
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	(10,699,900)	(7,795,800)
Derivative, Nonmonetary Notional Amount MWh	(10,092,300)	(6,119,100)
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	607,600	1,676,700
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	(10,699,900)	(7,795,800)
Derivative, Nonmonetary Notional Amount MWh	(10,092,300)	(6,119,100)

XML

Derivative Instruments and Hedging Activities (Gains or Losses Recognized in AOCI for the Cash Flow Hedges) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Forward Contract Power [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Beginning accumulated derivative gain / (loss) in AOCI	$ 3.4	$ 1.1	$ 9.2	$ 0.2
Net gains / (losses) associated with current period hedging transactions	9.5	7.8	22.4	9.6
Ending accumulated derivative gain / (loss) in AOCI	7.5	7.0	7.5	7.0
Portion expected to be reclassified to earnings in the next twelve months	0.0		$ 0.0
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)			15 months
Interest Rate Contract [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Beginning accumulated derivative gain / (loss) in AOCI	17.3	17.8	$ 17.5	18.3
Net gains / (losses) associated with current period hedging transactions	0.0	0.0	0.0	0.0
Ending accumulated derivative gain / (loss) in AOCI	17.2	17.7	17.2	17.7
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)			0 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	3.4	1.1	$ 9.2	0.2
Net gains / (losses) associated with current period hedging transactions	9.5	7.8	22.5	9.6
Ending accumulated derivative gain / (loss) in AOCI	7.5	7.0	7.5	7.0
Portion expected to be reclassified to earnings in the next twelve months	0.0		$ 0.0
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)			15 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	1.6	2.2	$ 2.0	2.6
Net gains / (losses) associated with current period hedging transactions	0.0	0.0	0.0	0.0
Ending accumulated derivative gain / (loss) in AOCI	1.4	2.1	1.4	2.1
Portion expected to be reclassified to earnings in the next twelve months	(0.7)		$ (0.7)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)			0 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	(0.1)	(0.1)	(0.3)	(0.6)
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)	(0.1)	(0.6)	(0.5)
Revenue [Member] | Forward Contract Power [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	(6.0)	(2.5)	(30.0)	(4.5)
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	(6.0)	(2.5)	(30.1)	(4.5)
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	0.6	0.6	5.9	1.7
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	0.6	0.6	5.9	1.7
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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Change in unrealized gain / (loss)	$ 0.9	$ (3.0)	$ 2.7	$ (4.2)
Realized loss	(2.3)	(4.6)	(5.0)	(8.6)
Derivative, Gain (Loss) on Derivative, Net	(1.4)	(7.6)	(2.3)	(12.8)
Commodity Contract - Heating Oil [Member]
Change in unrealized gain / (loss)		0.1		0.4
Realized loss		(0.2)		(0.3)
Derivative, Gain (Loss) on Derivative, Net		(0.1)		0.1
Commodity Contract - FTR [Member]
Change in unrealized gain / (loss)	0.0	0.1	0.4	0.2
Realized loss	(0.1)	(0.1)	(0.4)	(0.1)
Derivative, Gain (Loss) on Derivative, Net	(0.1)	0.0	0.0	0.1
Forward Contract Power [Member]
Change in unrealized gain / (loss)	1.2	(3.2)	2.3	(4.9)
Realized loss	(2.4)	(4.3)	(5.3)	(8.1)
Derivative, Gain (Loss) on Derivative, Net	(1.2)	(7.5)	(3.0)	(13.0)
Natural Gas [Member]
Change in unrealized gain / (loss)	(0.3)		0.0	0.1
Realized loss	0.2		0.7	(0.1)
Derivative, Gain (Loss) on Derivative, Net	(0.1)		0.7	0.0
THE DAYTON POWER AND LIGHT COMPANY [Member]
Change in unrealized gain / (loss)	0.9	(3.1)	2.7	(4.3)
Realized loss	(2.3)	(4.6)	(5.0)	(8.6)
Derivative, Gain (Loss) on Derivative, Net	(1.4)	(7.7)	(2.3)	(12.9)
THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member]
Change in unrealized gain / (loss)		0.1		0.4
Realized loss		(0.2)		(0.3)
Derivative, Gain (Loss) on Derivative, Net		(0.1)		0.1
THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Change in unrealized gain / (loss)	0.0	0.1	0.4	0.2
Realized loss	(0.1)	(0.1)	(0.4)	(0.1)
Derivative, Gain (Loss) on Derivative, Net	(0.1)	0.0	0.0	0.1
THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Change in unrealized gain / (loss)	1.2	(3.3)	2.3	(5.0)
Realized loss	(2.4)	(4.3)	(5.3)	(8.1)
Derivative, Gain (Loss) on Derivative, Net	(1.2)	(7.6)	(3.0)	(13.1)
THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Change in unrealized gain / (loss)	(0.3)		0.0	0.1
Realized loss	0.2		0.7	(0.1)
Derivative, Gain (Loss) on Derivative, Net	(0.1)		0.7	0.0
Regulatory Asset [Member]
Derivative, Gain (Loss) on Derivative, Net				0.1
Regulatory Asset [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net				0.1
Regulatory Asset [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net				0.0
Regulatory Asset [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net				0.0
Regulatory Asset [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net				0.0
Regulatory Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative, Gain (Loss) on Derivative, Net				0.1
Regulatory Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net				0.1
Regulatory Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net				0.0
Regulatory Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net				0.0
Regulatory Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net				0.0
Revenue [Member]
Derivative, Gain (Loss) on Derivative, Net	(10.4)	3.5	(13.1)	8.9
Revenue [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net		0.0		0.0
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	(10.4)	3.5	(13.1)	8.9
Revenue [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net	0.0		0.0	0.0
Revenue [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative, Gain (Loss) on Derivative, Net	(10.4)	3.4	(13.1)
Revenue [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net		0.0
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
Revenue [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net	(10.4)	3.4	(13.1)
Revenue [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net	0.0		0.0
Purchased Power [Member]
Derivative, Gain (Loss) on Derivative, Net	9.0	(11.0)	10.8	(21.8)
Purchased Power [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net		0.0		0.0
Purchased Power [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net	(0.1)	0.0	0.0	0.1
Purchased Power [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net	9.2	(11.0)	10.1	(21.9)
Purchased Power [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net	(0.1)		0.7	0.0
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative, Gain (Loss) on Derivative, Net	9.0	(11.0)	10.8	(21.8)
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net		0.0		0.0
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net	(0.1)	0.0	0.0	0.1
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net	9.2	(11.0)	10.1	(21.9)
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net	$ (0.1)	(0.1)	$ 0.7	0.0
Fuel [Member]
Derivative, Gain (Loss) on Derivative, Net		(0.1)
Fuel [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net		(0.1)
Fuel [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net		0.0
Fuel [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net		0.0
Fuel [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative, Gain (Loss) on Derivative, Net				8.8
Fuel [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net		(0.1)		0.0
Fuel [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net		0.0		0.0
Fuel [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net		$ 0.0		$ 8.8

XML

Derivative Instruments and Hedging Activities (Fair Value and Balance Sheet Location (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Derivative Liability, Fair Value	$ 30.9
Liability position offset by the asset position of counterparties with master netting agreements	22.7
THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value	31.0
Liability position offset by the asset position of counterparties with master netting agreements	5.1
Total Assets [Member]
Derivative Asset, Fair Value	33.2	$ 30.7
Derivative, Collateral, Obligation to Return Securities	(22.7)	(17.9)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	10.5	12.8
Total Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Asset, Fair Value	33.3	30.8
Derivative, Collateral, Obligation to Return Securities	(22.8)	(17.9)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	10.5	12.9
Total Liabilities [Member]
Derivative Liability, Fair Value	30.9	27.5
Derivative, Collateral, Right to Reclaim Securities	(22.7)	(17.9)
Derivative, Collateral, Right to Reclaim Cash	(5.1)	(8.0)
Liability position offset by the asset position of counterparties with master netting agreements	3.1	1.6
Total Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value	31.0	27.5
Derivative, Collateral, Right to Reclaim Securities	(22.8)	(17.9)
Derivative, Collateral, Right to Reclaim Cash	(5.1)	(8.0)
Liability position offset by the asset position of counterparties with master netting agreements	3.1	1.6
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	15.6	16.2
Derivative, Collateral, Obligation to Return Securities	(13.3)	(7.1)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	2.3	9.1
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	15.6	16.2
Derivative, Collateral, Obligation to Return Securities	(13.3)	(7.1)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	2.3	9.1
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	16.1	7.1
Derivative, Collateral, Right to Reclaim Securities	(13.3)	(7.1)
Derivative, Collateral, Right to Reclaim Cash	(2.7)	0.0
Liability position offset by the asset position of counterparties with master netting agreements	0.1	0.0
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	16.1	7.1
Derivative, Collateral, Right to Reclaim Securities	(13.3)	(7.1)
Derivative, Collateral, Right to Reclaim Cash	(2.7)	0.0
Liability position offset by the asset position of counterparties with master netting agreements	0.1	0.0
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member]
Derivative Asset, Fair Value	7.4	3.0
Derivative, Collateral, Obligation to Return Securities	(1.1)	(2.4)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	6.3	0.6
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	7.4	3.0
Derivative, Collateral, Obligation to Return Securities	(1.1)	(2.4)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	6.3	0.6
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative Liability, Fair Value	1.1	2.7
Derivative, Collateral, Right to Reclaim Securities	(1.1)	(2.4)
Derivative, Collateral, Right to Reclaim Cash	0.0	0.0
Liability position offset by the asset position of counterparties with master netting agreements	0.0	0.3
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	1.1	2.7
Derivative, Collateral, Right to Reclaim Securities	(1.1)	(2.4)
Derivative, Collateral, Right to Reclaim Cash	0.0	0.0
Liability position offset by the asset position of counterparties with master netting agreements	0.0	0.3
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	0.2
Derivative, Collateral, Obligation to Return Securities	0.0	(0.2)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0.1	0.0
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	0.2
Derivative, Collateral, Obligation to Return Securities	0.0	(0.2)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0.1	0.0
Fair Value Hedging [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value		0.5
Derivative, Collateral, Right to Reclaim Securities		(0.2)
Derivative, Collateral, Right to Reclaim Cash		0.0
Liability position offset by the asset position of counterparties with master netting agreements		0.3
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		0.5
Derivative, Collateral, Right to Reclaim Securities		(0.2)
Derivative, Collateral, Right to Reclaim Cash		0.0
Liability position offset by the asset position of counterparties with master netting agreements		0.3
Fair Value Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	8.7	7.3
Derivative, Collateral, Obligation to Return Securities	(7.6)	(5.5)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	1.1	1.8
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	8.8	7.4
Derivative, Collateral, Obligation to Return Securities	(7.7)	(5.5)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	1.1	1.9
Fair Value Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	12.8	14.5
Derivative, Collateral, Right to Reclaim Securities	(7.6)	(5.5)
Derivative, Collateral, Right to Reclaim Cash	(2.4)	(8.0)
Liability position offset by the asset position of counterparties with master netting agreements	2.8	1.0
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	12.9	14.5
Derivative, Collateral, Right to Reclaim Securities	(7.7)	(5.5)
Derivative, Collateral, Right to Reclaim Cash	(2.4)	(8.0)
Liability position offset by the asset position of counterparties with master netting agreements	2.8	1.0
Fair Value Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member]
Derivative Asset, Fair Value	1.4	4.0
Derivative, Collateral, Obligation to Return Securities	(0.7)	(2.7)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0.7	1.3
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	1.4	4.0
Derivative, Collateral, Obligation to Return Securities	(0.7)	(2.7)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0.7	1.3
Fair Value Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative Liability, Fair Value	0.9	2.7
Derivative, Collateral, Right to Reclaim Securities	(0.7)	(2.7)
Derivative, Collateral, Right to Reclaim Cash	0.0	0.0
Liability position offset by the asset position of counterparties with master netting agreements	0.2	0.0
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	0.9	2.7
Derivative, Collateral, Right to Reclaim Securities	(0.7)	(2.7)
Derivative, Collateral, Right to Reclaim Cash	0.0	0.0
Liability position offset by the asset position of counterparties with master netting agreements	$ 0.2	$ 0.0

XML

Debt (Narrative) (Details) $ in Millions			9 Months Ended
	Oct. 17, 2016 USD ($)	Feb. 05, 2016 USD ($)	Sep. 30, 2016 USD ($) fiscal_quarter debt_covenant	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Debt Instrument [Line Items]
Retirement of long-term debt			$ 520.8	$ 474.5
THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Retirement of long-term debt			445.3	$ 314.5
Senior unsecured due in October 2016 - 6.5% [Member]
Debt Instrument [Line Items]
Debt called/redeemed		$ 73.0
Term loan outstanding			$ 57.0		$ 130.0
Debt instrument interest percentage			6.50%		6.50%
Debt Instrument, Basis Spread on Variable Rate		0.50%
Retirement of long-term debt		$ 75.4
One Point Nine Percentage Of First Mortgage Bonds Maturing September Two Thousand Sixteen [Member]
Debt Instrument [Line Items]
Term loan outstanding					$ 445.0
Debt instrument interest percentage			1.875%		1.875%
One Point Nine Percentage Of First Mortgage Bonds Maturing September Two Thousand Sixteen [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Term loan outstanding			$ 0.0		$ 445.0
Debt instrument interest percentage			1.875%		1.875%
Term Loan Maturing 2022 [Member]
Debt Instrument [Line Items]
Term loan outstanding			$ 445.0		$ 0.0
Debt Instrument, Basis Spread on Variable Rate			3.25%
Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Term loan outstanding			$ 445.0		$ 0.0
Debt Instrument, Basis Spread on Variable Rate			3.25%
Revolving Credit Agreement and Standby Letters of Credit [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Number of financial covenants | 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] | Senior unsecured due in October 2016 - 6.5% [Member]
Debt Instrument [Line Items]
Debt called/redeemed	$ 57.0

XML

Debt (Long-term Debt) (Details) - USD ($) $ in Millions		9 Months Ended	12 Months Ended
	Feb. 05, 2016	Sep. 30, 2016	Dec. 31, 2015	Mar. 31, 2017
Debt Instrument [Line Items]
Unamortized deferred finance costs		$ (5.6)	$ (5.0)
Unamortized deferred finance costs		(9.3)	(11.1)
Unamortized debt discount and premiums, net		(0.6)	(0.7)
Total long-term debt at subsidiary		746.3	754.5
Total long-term debt		1,914.0	1,993.3
Less: current portion		(79.2)	(572.8)
Long-term debt		$ 1,834.8	1,420.5
Long-term debt, earliest maturities		2016
Long-term debt, latest maturities		2061
THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Unamortized deferred finance costs		$ (12.3)	(6.2)
Unamortized debt discount and premiums, net		(11.1)	(3.6)
Unamortized debt discount		(2.2)	(0.2)
Total long-term debt		748.5	756.7
Less: current portion		(3.5)	(443.1)
Long-term debt		$ 745.0	313.6
Long-term debt, earliest maturities		2016
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		$ 445.0	$ 0.0
Debt Instrument, Basis Spread on Variable Rate		3.25%
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum		4.00%
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum		0.75%
Debt instrument interest percentage maximum		4.00%
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Maximum
Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 445.0	$ 0.0
Debt Instrument, Basis Spread on Variable Rate		3.25%
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum		4.00%
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum		0.75%
Debt instrument interest percentage maximum		4.00%
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Maximum
One Point Nine Percentage Of First Mortgage Bonds Maturing September Two Thousand Sixteen [Member]
Debt Instrument [Line Items]
Long-term debt, gross			$ 445.0
Debt instrument maturity year		Sep. 01, 2016
Debt instrument interest percentage		1.875%	1.875%
One Point Nine Percentage Of First Mortgage Bonds Maturing September Two Thousand Sixteen [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 0.0	$ 445.0
Debt instrument maturity year		Sep. 01, 2016
Debt instrument interest percentage		1.875%	1.875%
Pollution Control Series Maturing in September 2036 - 4.80% [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 100.0	$ 100.0
Debt instrument maturity year		Sep. 01, 2036
Debt instrument interest percentage		4.80%
Pollution Control Series Maturing in September 2036 - 4.80% [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 100.0	$ 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
Debt instrument interest percentage minimum			1.13%
Debt instrument interest percentage maximum			1.17%
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
Zero Point Two Three To Zero Point Two Nine And Zero Point One Six To Zero Point Three Six Percentage Of Pollution Control Series Maturing In November Two Thousand Forty [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage minimum		1.29%
Debt instrument interest percentage maximum		1.36%
Zero Point Two Three To Zero Point Two Nine And Zero Point One Six To Zero Point Three Six Percentage Of Pollution Control Series Maturing In November Two Thousand Forty [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage minimum		1.29%	1.13%
Debt instrument interest percentage maximum		1.36%	1.17%
U.S. Government note maturing in February 2061 - 4.20% [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 18.0	$ 18.1
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		$ 18.0	18.1
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		$ 125.0	$ 125.0
Debt instrument maturity year		Jul. 31, 2020
Debt instrument interest percentage minimum		2.67%	2.44%
Debt instrument interest percentage maximum		2.77%	2.67%
Senior unsecured due in October 2016 - 6.5% [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 57.0	$ 130.0
Debt Instrument, Basis Spread on Variable Rate	0.50%
Debt instrument maturity year		Oct. 01, 2016
Debt instrument interest percentage		6.50%	6.50%
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] | Term Loan Maturing 2022 [Member]
Debt Instrument [Line Items]
Quarterly Loan Amortization of Initial Principal Balance				0.25%
Subsequent Event [Member] | Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Quarterly Loan Amortization of Initial Principal Balance				0.25%

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Income Taxes (Narrative) (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Entity Information [Line Items]
Effective income tax rates	45.70%	(34.10%)	38.60%	24.60%
Estimated annual effective income tax rate			38.60%	30.80%
THE DAYTON POWER AND LIGHT COMPANY [Member]
Entity Information [Line Items]
Effective income tax rates	39.60%	4.90%	36.70%	24.80%
Estimated annual effective income tax rate			36.70%	29.00%

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Benefit Plans (Net Periodic Benefit Cost (Income)) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension [Member]
Contributions by employer			$ 5.0	$ 5.0
Service cost	$ 1.4	$ 1.7	4.2	5.3
Interest cost	3.7	4.4	11.1	13.0
Expected return on assets	(5.7)	(5.7)	(17.1)	(17.0)
Prior service cost	0.4	0.5	1.4	1.5
Actuarial loss / (gain)	1.1	1.5	3.2	4.4
Net periodic benefit cost	0.9	2.4	2.8	7.2
Postretirement [Member]
Service cost	0.0	0.1	0.1	0.1
Interest cost	0.2	0.2	0.4	0.5
Expected return on assets	(0.1)	(0.1)	(0.1)	(0.1)
Prior service cost	0.0	0.0	0.0	0.0
Actuarial loss / (gain)	(0.1)	(0.1)	(0.4)	(0.3)
Net periodic benefit cost	0.0	0.1	0.0	0.2
THE DAYTON POWER AND LIGHT COMPANY [Member] | Pension [Member]
Contributions by employer			5.0	5.0
Service cost	1.4	1.8	4.2	5.3
Interest cost	3.7	4.2	11.1	12.8
Expected return on assets	(5.7)	(5.6)	(17.1)	(16.8)
Prior service cost	0.8	0.9	2.3	2.5
Actuarial loss / (gain)	1.8	2.4	5.4	7.2
Net periodic benefit cost	2.0	3.7	5.9	11.0
THE DAYTON POWER AND LIGHT COMPANY [Member] | Postretirement [Member]
Service cost	0.0	0.1	0.1	0.1
Interest cost	0.1	0.1	0.4	0.5
Expected return on assets	(0.1)	(0.1)	(0.1)	(0.1)
Prior service cost	0.1	0.1	0.1	0.1
Actuarial loss / (gain)	(0.1)	(0.2)	(0.5)	(0.5)
Net periodic benefit cost	$ 0.0	$ 0.0	$ 0.0	$ 0.1

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Benefit Plans (Estimated Future Benefit Payments and Medicare Part D Reimbursements) (Details) $ in Millions	Sep. 30, 2016 USD ($)
Pension [Member]
2016	$ 6.2
2017	25.2
2018	25.8
2019	26.3
2020	26.7
2021 - 2025	134.8
Postretirement [Member]
2016	0.4
2017	1.6
2018	1.5
2019	1.4
2020	1.4
2021 - 2025	5.7
THE DAYTON POWER AND LIGHT COMPANY [Member] | Pension [Member]
2016	6.2
2017	25.2
2018	25.8
2019	26.3
2020	26.7
2021 - 2025	134.8
THE DAYTON POWER AND LIGHT COMPANY [Member] | Postretirement [Member]
2016	0.4
2017	1.6
2018	1.5
2019	1.4
2020	1.4
2021 - 2025	$ 5.7

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Shareholder's Equity (Details) - USD ($)	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Jan. 01, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Preferred Stock, Redemption Amount	$ 23,500,000
Accounts Payable, Related Parties, Current	$ 1,400,000			$ 500,000
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]
Preferred Stock, Redemption Amount	$ 23,500,000
Accounts Payable, Related Parties, Current	$ 1,400,000			$ 500,000
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	50.00%
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%
Subsidiary of Common Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Class of Stock [Line Items]
Equity Settlement of Related Party Payable	$ 7,500,000	$ 0
Accounts Payable, Related Parties, Current			$ 7,500,000

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Shareholder's Equity Equity Settlement of Related Party Payable (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Jan. 01, 2016	Dec. 31, 2015
Accounts Payable, Related Parties, Current	$ 1.4			$ 0.5
Subsidiaries [Member]
Accounts Payable, Related Parties, Current	1.4			$ 0.5
Subsidiaries [Member] | Subsidiary of Common Parent [Member]
Accounts Payable, Related Parties, Current			$ 7.5
Equity Settlement of Related Party Payable	$ 7.5	$ 0.0

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Redeemable Preferred Stock of Subsidiary (Details) $ / shares in Units, $ in Millions	Sep. 30, 2016 USD ($) $ / shares
Temporary Equity [Line Items]
Preferred Stock, Redemption Amount | $	$ 23.5
Dp L Seriesa [Member]
Temporary Equity [Line Items]
Temporary Equity, Preferred Stock Rate	3.75%
Temporary Equity, Redemption Price Per Share	$ 102.50
Dp L Series B [Member]
Temporary Equity [Line Items]
Temporary Equity, Preferred Stock Rate	3.75%
Temporary Equity, Redemption Price Per Share	$ 103.00
Dp L Series C [Member]
Temporary Equity [Line Items]
Temporary Equity, Preferred Stock Rate	3.90%
Temporary Equity, Redemption Price Per Share	$ 101.00
Subsidiaries [Member]
Temporary Equity [Line Items]
Preferred Stock, Redemption Amount | $	$ 23.5
Subsidiaries [Member] | Dp L Seriesa [Member]
Temporary Equity [Line Items]
Temporary Equity, Preferred Stock Rate	3.75%
Temporary Equity, Redemption Price Per Share	$ 102.50
Subsidiaries [Member] | Dp L Series B [Member]
Temporary Equity [Line Items]
Temporary Equity, Preferred Stock Rate	3.75%
Temporary Equity, Redemption Price Per Share	$ 103.00
Subsidiaries [Member] | Dp L Series C [Member]
Temporary Equity [Line Items]
Temporary Equity, Preferred Stock Rate	3.90%
Temporary Equity, Redemption Price Per Share	$ 101.00

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Contractual Obligations, Commercial Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Due to third parties, current	$ 4.8	$ 0.5
THE DAYTON POWER AND LIGHT COMPANY [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt maturity, earliest	2018
Debt maturity, latest	2040
DPLE [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Third party guarantees	$ 16.6
Debt Obligation on 4.9% Equity Ownership [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Equity ownership interest	4.90%
Equity ownership interest aggregate cost	$ 74.9
Electric Generation Company [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt obligation	$ 1,528.0

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Related Party Transactions (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended		12 Months Ended
	Dec. 31, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Jan. 01, 2016
Related Party Transaction [Line Items]
Charges for services provided		$ 9.7	$ 8.9	$ 32.8	$ 28.5
Sales to related party		1.1	1.1	3.4	5.1
Net payable to the Service Company	$ (0.5)	(1.4)		(1.4)		$ (0.5)
Investment in trust	$ 0.3	0.3		0.3		0.3
Debt Instrument, Interest Rate, Stated Percentage	2.67%
Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member]
Related Party Transaction [Line Items]
Note payable to trust	$ 15.6	15.6		15.6		15.6
Prepaid Expenses and Other Current Assets [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current
Accrued Liabilities [Member]
Related Party Transaction [Line Items]
Net payable to the Service Company	(50.5)	(97.0)		(97.0)		(50.5)
Charges for health, welfare and benefit plans [Member] | Subsidiary of Common Parent [Member]
Related Party Transaction [Line Items]
Transactions with other AES affiliates		3.9	4.3	5.6	12.5
THE DAYTON POWER AND LIGHT COMPANY [Member]
Related Party Transaction [Line Items]
Charges for services provided		9.4	7.6	29.2	24.3
Sales to related party		1.1	1.1	3.3	5.0
Premiums paid for insurance services provided by MVIC		(0.8)	(0.8)	(2.5)	(2.4)
Expense recoveries for services provided to DPLER		0.0	0.6	0.0	1.8
Net payable to the Service Company	(0.5)	(1.4)		(1.4)		(0.5)
Gain on termination of contract		0.0	0.0	27.7	0.0
Notes Payable, Related Parties				(5.0)	0.0	(35.0)
Notes Payable, Related Parties	35.0	0.0		0.0		35.0
Accounts Receivable, Related Parties, Current	2.8	4.3		4.3		2.8
THE DAYTON POWER AND LIGHT COMPANY [Member] | Prepaid Expenses and Other Current Assets [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	1.5					1.5
THE DAYTON POWER AND LIGHT COMPANY [Member] | Accrued Liabilities [Member]
Related Party Transaction [Line Items]
Net payable to the Service Company		(36.2)		(36.2)
THE DAYTON POWER AND LIGHT COMPANY [Member] | Subsidiary of Common Parent [Member]
Related Party Transaction [Line Items]
Net payable to the Service Company							$ (7.5)
Equity Settlement of Related Party Payable				7.5	0.0
THE DAYTON POWER AND LIGHT COMPANY [Member] | Insurance Proceeds Received [Member] | Subsidiary of Common Parent [Member]
Related Party Transaction [Line Items]
Transactions with other AES affiliates		0.2	0.5	0.4	4.3
THE DAYTON POWER AND LIGHT COMPANY [Member] | Charges for health, welfare and benefit plans [Member] | Subsidiary of Common Parent [Member]
Related Party Transaction [Line Items]
Transactions with other AES affiliates		3.8	4.1	5.5	11.9
THE DAYTON POWER AND LIGHT COMPANY [Member] | Dpler [Member]
Related Party Transaction [Line Items]
Sales to related party		$ 0.0	$ 66.0	$ 0.0	$ 245.0

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Business Segments (Narrative) (Details)	9 Months Ended
	Sep. 30, 2016 mi² segment customer power_plant
Segment Reporting Information [Line Items]
Number of operating segments | segment	2
THE DAYTON POWER AND LIGHT COMPANY [Member]
Segment Reporting Information [Line Items]
Number of coal fired power plants | power_plant	5
Approximate number of retail customers | customer	518,000
Service area, square miles | mi²	6,000

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Business Segments (Segment Financial Information) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
External customer revenues	$ 389.3	$ 414.1	$ 1,081.6	$ 1,281.5
Total revenues	389.3	414.1	1,081.6	1,281.5
Fuel Costs	78.9	71.4	206.0	202.2
Purchased power	111.7	145.4	330.5	460.2
Gross margin	198.7	197.3	545.1	619.1
Depreciation and amortization	30.9	34.8	100.3	104.1
Impairment of Long-Lived Assets Held-for-use	0.0	0.0	235.5	0.0
Interest expense	27.0	28.9	79.3	90.3
Income tax expense / (benefit)	12.7	0.3	(75.0)	13.5
Net income / (loss) from continuing operations	15.1	5.5	(119.5)	47.1
Discontinued operations, net of tax	0.0	3.1	29.6	11.9
Net income/ (loss)	15.1	8.6	(89.9)	59.0
Capital expenditures	30.7	28.7	109.8	93.5
Total assets	2,950.4		2,950.4		$ 3,324.7
Operating Segments [Member] | Utility [Member]
Segment Reporting Information [Line Items]
External customer revenues	368.0	323.2	1,030.3	957.6
Intersegment revenues	0.4	66.0	1.0	245.0
Total revenues	368.4	389.2	1,031.3	1,202.6
Fuel Costs	71.0	69.0	189.5	188.9
Purchased power	110.0	142.5	328.0	452.3
Gross margin	187.4	177.7	513.8	561.4
Depreciation and amortization	24.1	34.6	95.2	103.5
Impairment of Long-Lived Assets Held-for-use			857.1
Interest expense	6.5	6.9	17.2	24.6
Income tax expense / (benefit)	19.7	0.8	(271.6)	25.0
Net income / (loss) from continuing operations			(467.8)
Discontinued operations, net of tax			0.0
Net income/ (loss)	30.1	15.5	(467.8)	75.9
Capital expenditures	26.5	27.9	98.3	91.2
Total assets	2,460.8		2,460.8		3,359.6
Operating Segments [Member] | Competitive Retail [Member]
Segment Reporting Information [Line Items]
External customer revenues		77.0		274.5
Intersegment revenues		0.0		0.0
Total revenues		77.0		274.5
Fuel Costs		0.0		0.0
Purchased power		66.6		247.0
Gross margin		10.4		27.5
Depreciation and amortization		0.2		0.6
Interest expense		0.0		0.1
Income tax expense / (benefit)		1.6		(2.6)
Net income/ (loss)		2.6		10.9
Capital expenditures		0.3		0.6
Total assets					0.0
Other [Member]
Segment Reporting Information [Line Items]
External customer revenues	21.3	13.9	51.3	49.4
Intersegment revenues	2.0	1.5	4.2	4.4
Total revenues	23.3	15.4	55.5	53.8
Fuel Costs	7.9	2.4	16.5	13.3
Purchased power	3.0	3.0	4.9	7.8
Gross margin	12.4	10.0	34.1	32.7
Depreciation and amortization	6.8	0.0	5.1	0.0
Impairment of Long-Lived Assets Held-for-use			(621.6)
Interest expense	20.3	22.1	61.6	65.8
Income tax expense / (benefit)	(7.0)	(2.1)	196.6	(8.9)
Net income / (loss) from continuing operations			348.3
Discontinued operations, net of tax			29.6
Net income/ (loss)	(15.0)	(9.5)	377.9	(27.8)
Capital expenditures	4.2	0.5	11.5	1.7
Total assets	1,303.8		1,303.8		1,304.5
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
External customer revenues	0.0	0.0	0.0	0.0
Intersegment revenues	(2.4)	(67.5)	(5.2)	(249.4)
Total revenues	(2.4)	(67.5)	(5.2)	(249.4)
Fuel Costs	0.0	0.0	0.0	0.0
Purchased power	(1.3)	(66.7)	(2.4)	(246.9)
Gross margin	(1.1)	(0.8)	(2.8)	(2.5)
Depreciation and amortization	0.0	0.0	0.0	0.0
Impairment of Long-Lived Assets Held-for-use			0.0
Interest expense	0.2	(0.1)	0.5	(0.2)
Income tax expense / (benefit)	0.0	0.0	0.0	0.0
Net income / (loss) from continuing operations			0.0
Discontinued operations, net of tax			0.0
Net income/ (loss)	0.0	0.0	0.0	0.0
Capital expenditures	0.0	$ 0.0	0.0	$ 0.0
Total assets	$ (814.2)		$ (814.2)		$ (1,339.4)

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Discontinued Operations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable, net					$ 31.0
Deposit received on sale of DPLER	$ 0.0		$ 0.0		75.5
Property, plant & equipment, net					4.6
Intangible assets, net					24.6
Other assets					2.0
Total assets of the disposal group classified as held for sale in the balance sheets					62.2
Accounts payable					0.8
Other liabilities					0.8
Total liabilities of the disposal group classified as held for sale in the balance sheets					1.6
Revenues	0.0	$ 77.1	0.0	$ 274.6
Cost of revenues	0.0	(66.5)	0.0	(247.0)
Operating expenses	0.0	(5.7)	(0.7)	(17.5)
(Loss) / income from discontinued operations before income taxes	0.0	4.9	(0.7)	10.1
Gain from disposal of discontinued operations	0.0	0.0	49.2	0.0
Income tax expense / (benefit) for discontinued operations	0.0	1.8	18.9	(1.8)
Discontinued operations	$ 0.0	$ 3.1	29.6	11.9
Cash flows from operating activities for discontinued operations			(0.7)	28.4
Cash flows from investing activities for discontinued operations			$ 75.5	$ 0.7
Dpler [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deposit received on sale of DPLER					$ 75.5

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Fixed-asset Impairment Fixed-asset Impairment (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Impairment of Long-Lived Assets Held-for-use	$ 0.0	$ 0.0	$ 235.5	$ 0.0
Killen [Member]
Impairment of Long-Lived Assets Held-for-use			230.8
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	$ 0.0	857.1	$ 0.0
THE DAYTON POWER AND LIGHT COMPANY [Member] | Stuart [Member]
Impairment of Long-Lived Assets Held-for-use			292.0
THE DAYTON POWER AND LIGHT COMPANY [Member] | Killen [Member]
Impairment of Long-Lived Assets Held-for-use			246.2
THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [Member]
Impairment of Long-Lived Assets Held-for-use			318.9
Level 3 [Member] | Killen [Member]
Property, Plant, and Equipment, Fair Value Disclosure	84.3		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	164.4		164.4
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Killen [Member]
Property, Plant, and Equipment, Fair Value Disclosure	84.3		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