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~~2017

( ) 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

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



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

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



DPL Inc.	o
The Dayton Power and Light Company	o

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



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

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

As of November ~~3, 2016,~~1, 2017, each registrant had the following shares of common stock outstanding:



Registrant	Description	Shares Outstanding

DPL Inc.	Common Stock, no par value	1

The Dayton Power and Light Company	Common Stock, $0.01 par value	41,172,173

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

DPL Inc. and The Dayton Power and Light Company

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Quarterly Report on Form 10-Q

Quarter Ended September 30, ~~2016~~2017



		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	4041

	Condensed Statements of Comprehensive Income / (Loss)	4142

	Condensed Balance Sheets	4243

	Condensed Statements of Cash Flows	4344

	Notes to Condensed Financial Statements	4445

Item 2	Management’s Discussion and Analysis of Financial Condition and Operations	6570

	Electric Sales and Customers	89110

Item 3	Quantitative and Qualitative Disclosures about Market Risk	89110

Item 4	Controls and Procedures	89110

DPL Inc. and The Dayton Power and Light Company

Table of Contents (cont.)

Quarterly Report on Form 10-Q

Quarter Ended September 30, ~~2016~~2017



		Page No.
Part II Other Information

Item 1	Legal Proceedings	89111

Item 1A	Risk Factors	90111

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	90111

Item 3	Defaults Upon Senior Securities	90112

Item 4	Mine Safety Disclosures	90112

Item 5	Other Information	90112

Item 6	Exhibits	91113

Other

	Signatures	92114

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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~~CCR	~~Clean Air Interstate Rule~~Coal combustion residuals
CP	In 2015, PJM adopted changes to the capacity market known as “Capacity Performance”. The CP program offers the potential for higher capacity revenues, combined with substantially increased penalties for non-performance or under-performance during certain periods identified as “capacity performance hours.” The DP&L units operate under the CP construct effective June 1, 2016.
~~CRES~~CPP	~~Competitive Retail Electric Service~~Clean Power Plan
~~CSAPR~~D.C. Circuit Court	~~Cross-State Air Pollution Rule~~United States Court of Appeals for the District of Columbia Circuit
DPL	DPL Inc.
DPLER	DPL Energy Resources, Inc., formerly a wholly-owned subsidiary of DPL which sold competitive electric energy and other energy services. DPLER was sold by DPL on January 1, 2016. The DPLER sale agreement was signed on December 28, 2015.
DP&L	The Dayton Power and Light Company, the principal subsidiary of DPL and a public utility that delivers electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio
Dths	Decatherms, unit of heat energy equal to 10 therms. One therm is equal to 100,000 British Thermal Units
EBITDA	Earnings before interest, taxes, depreciation and amortization. EBITDA also excludes the Fixed-asset impairment
EGU	Electric Generating Unit
ERISA	The Employee Retirement Income Security Act of 1974
ESP	The Electric Security Plan is a plan that a utility must file with the PUCO to establish SSO rates pursuant to Ohio law
ESP 1	ESP approved by PUCO order dated June 24, 2009
ESP 2	ESP approved by PUCO order dated September 4, 2013. The Ohio Supreme Court ruled that it was invalid. DP&L withdrew its ESP 2 on July 27, 2016 and filed ~~an amended application on October 11, 2016.~~to reinstate previously authorized rates from ESP 1
ESP 3	ESP filed with the PUCO by DP&L on February 22, 2016 and an amended application filed on October 11, 2016
~~FASC~~FASB	Financial Accounting Standards Board ~~(FASB)~~
FASC	FASB Accounting Standards Codification
FERC	Federal Energy Regulatory Commission
FGD	Flue Gas Desulfurization
Form 10-K	DPL’s and DP&L’s combined Annual Report on Form 10-K for the fiscal year ended December 31, ~~2015,~~2016, which was filed on February ~~23, 2016~~28, 2017

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GLOSSARY OF TERMS (cont.)

Term	Definition
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

~~Table of Contents~~


Generation Separation
~~GLOSSARY OF TERMS (cont.)~~

~~Term~~	~~Definition~~ The transfer on October 1, 2017 to AES Ohio Generation of the DP&L-owned generating facilities and related liabilities pursuant to an asset contribution agreement with a subsidiary that was then merged into AES Ohio Generation
GHG	Greenhouse Gas
kV	Kilovolt, 1,000 volts
kWh	Kilowatt-hours
LIBOR	London Inter-Bank Offering Rate
Master Trust	DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans
Merger	The merger of DPL and Dolphin Sub, Inc., a wholly-owned subsidiary of AES. On November 28, 2011, DPL became a wholly-owned subsidiary of AES.
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~~jointly-owned facilities operated by DP&L
MW	Megawatt
MWh	Megawatt-hour
NAV	Net asset value
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
Non-bypassable	Charges that are assessed to all customers regardless of whom the customer selects as their retail electric generation supplier
NOV	Notice of Violation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NSPS	New Source Performance Standards
NYMEX	New York Mercantile Exchange
Ohio EPA	Ohio Environmental Protection Agency
OTC	Over-The-Counter
OVEC	Ohio Valley Electric Corporation, an electric generating company in which DP&L holds a 4.9% equity interest
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
SCR	Selective Catalytic Reduction
SEC	Securities and Exchange Commission
SEET	Significantly excessive earnings test
SERP	Supplemental Executive Retirement Plan

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GLOSSARY OF TERMS (cont.)

Term	Definition
Service Company	AES US Services, LLC, the shared services affiliate providing accounting, finance, and other support services to AES’ U.S. SBU businesses
SO2	Sulfur Dioxide
SSO	Standard Service Offer represents the regulated rates, authorized by the PUCO, charged to DP&L retail customers that take retail generation service from DP&L within DP&L’s service territory
T&D	DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers
USEPA	U.S. Environmental Protection Agency
USD	U.S. dollar
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.~~

~~Table of Contents~~

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;

compliance with, changes in and liabilities under 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;

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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~~2016 and the “Management’s Discussion and Analysis of Financial Condition and Results of

~~Table of Contents~~

Operations” section in such report and in our Quarterly ~~Report~~Reports on Form 10-Q for the quarters ended June 30, and March 31, ~~2016~~2017 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.

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																									DPL INC.	CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
	Three months ended September 30,						Nine months ended September 30,						Three months ended						Nine months ended
													September 30,						September 30,
$ in millions	2016			2015			2016			2015			2017			2016			2017			2016
Revenues	$	389.3		$	403.3		$	1,081.6		$	1,252.1		$	323.9		$	389.3		$	945.9		$	1,081.6

Cost of revenues:
Fuel	78.9			71.4			206.0			202.2
Purchased power	111.7			144.9			330.5			458.5
Net fuel cost													57.3			78.9			165.4			206.0
Net purchased power cost													84.0			111.7			263.4			330.5
Total cost of revenues	190.6			216.3			536.5			660.7			141.3			190.6			428.8			536.5

Gross margin	198.7			187.0			545.1			591.4			182.6			198.7			517.1			545.1

Operating expenses:
Operation and maintenance	91.5			95.8			257.2			267.4			81.9			91.5			250.3			257.2
Depreciation and amortization	30.9			33.8			100.3			100.9			27.3			30.9			81.8			100.3
General taxes	21.6			21.7			64.2			66.7			20.1			21.6			68.3			64.2
Fixed-asset impairment	—			—			235.5			—			—			—			66.4			235.5
Loss / (gain) on asset disposal													(0.3		)	—			15.9			0.1
Other	(0.7		)	0.2			(0.6		)	0.4			(5.2		)	(0.7		)	(6.1		)	(0.7		)
Total operating expenses	143.3			151.5			656.6			435.4			123.8			143.3			476.6			656.6

Operating income / (loss)	55.4			35.5			(111.5		)	156.0			58.8			55.4			40.5			(111.5		)

Other income / (expense), net
Investment income	0.1			0.1			0.3			0.1			0.1			0.1			0.2			0.3
Interest expense	(27.0		)	(28.9		)	(79.3		)	(90.3		)	(27.2		)	(27.0		)	(81.5		)	(79.3		)
Charge for early retirement of debt	(0.5		)	(2.1		)	(3.1		)	(2.1		)
Charge for early redemption of debt													(3.0		)	(0.5		)	(3.3		)	(3.1		)
Other expense	(0.2		)	(0.5		)	(0.9		)	(1.2		)	(0.7		)	(0.2		)	(2.3		)	(0.9		)
Total other expense, net	(27.6		)	(31.4		)	(83.0		)	(93.5		)	(30.8		)	(27.6		)	(86.9		)	(83.0		)

Earnings / (loss) from continuing operations before income taxes	27.8			4.1			(194.5		)	62.5
Income / (loss) from continuing operations before income tax													28.0			27.8			(46.4		)	(194.5		)

Income tax expense / (benefit) from continuing operations	12.7			(1.4		)	(75.0		)	15.4			6.1			12.7			(17.1		)	(75.0		)

Net income / (loss) from continuing operations	15.1			5.5			(119.5		)	47.1			21.9			15.1			(29.3		)	(119.5		)

Discontinued operations (Note 13)
Income / (loss) from discontinued operations	—			4.9			(0.7		)	10.1
Discontinued operations (Note 12)
Loss from discontinued operations													—			—			—			(0.7		)
Gain from disposal of discontinued operations	—			—			49.2			—			—			—			—			49.2
Income tax expense / (benefit) for discontinued operations	—			1.8			18.9			(1.8		)
Discontinued operations	—			3.1			29.6			11.9
Income tax expense for discontinued operations													—			—			—			18.9
Net income from discontinued operations													—			—			—			29.6

Net income / (loss)	$	15.1		$	8.6		$	(89.9	)	$	59.0		$	21.9		$	15.1		$	(29.3	)	$	(89.9	)

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,						Three months ended September 30,						Nine months ended September 30,
$ in millions	2016			2015			2016			2015			2017			2016			2017			2016
Net income / (loss)	$	15.1		$	8.6		$	(89.9	)	$	59.0		$	21.9		$	15.1		$	(29.3	)	$	(89.9	)
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			(0.2		)
Change in fair value of available-for-sale securities, net of income tax expense of $(0.1), $0.0, $(0.2) and $(0.1) for each respective period													0.1			0.1			0.4			0.2
Reclassification to earnings, net of income tax expense of $0.0 for each respective period													—			—			(0.1		)	—
Total change in fair value of available-for-sale securities													0.1			0.1			0.3			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		)
Change in derivative fair value, net of income tax expense of $(0.8), $(5.2), $(6.6) and $(12.3) for each respective period													1.4			9.5			12.1			22.4
Reclassification to earnings, net of income tax benefit of $1.3, $3.0, $3.3 and $13.8 for each respective period													(2.4		)	(5.5		)	(6.0		)	(24.4		)
Total change in fair value of derivatives	4.0			5.8			(2.0		)	6.2			(1.0		)	4.0			6.1			(2.0		)
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		)
Prior service cost for the period, net of income tax benefit of $0.0, $0.0, $0.2 and $0.0 for each respective period													—			—			(0.3		)	—
Net loss for period, net of income tax benefit of $0.0, $0.0, $0.7 and $0.0 for each respective period													—			—			(1.2		)	—
Reclassification to earnings, net of income tax expense of $0.0, $0.0, $(0.5) and $(0.1) for each respective period													—			—			0.9			0.1
Total change in unfunded pension obligation													—			—			(0.6		)	0.1

Other comprehensive income / (loss)	4.1			5.6			(1.7		)	5.9			(0.9		)	4.1			5.8			(1.7		)

Net comprehensive income / (loss)	$	19.2		$	14.2		$	(91.6	)	$	64.9		$	21.0		$	19.2		$	(23.5	)	$	(91.6	)

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			September 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	121.8		$	32.4		$	23.4		$	54.6
Restricted cash	11.6			92.7			2.0			29.0
Accounts receivable, net (Note 2)	134.9			120.9			111.4			135.1
Inventories (Note 2)	80.0			109.1			28.7			77.2
Taxes applicable to subsequent years	19.7			81.2			19.6			81.0
Regulatory assets, current	—			14.4			4.5			0.1
Other prepayments and current assets	37.7			44.5			23.4			31.8
Assets held for sale, current	—			62.2
Assets held for sale - current (Note 13)							57.0			—
Total current assets	405.7			557.4			270.0			408.8

Property, plant & equipment:
Property, plant & equipment	2,701.2			2,909.0			1,963.5			1,985.6
Less: Accumulated depreciation and amortization	(479.6		)	(432.3		)	(372.6		)	(334.8		)
	2,221.6			2,476.7			1,590.9			1,650.8
Construction work in process	112.1			85.0			70.8			116.4
Total net property, plant & equipment	2,333.7			2,561.7			1,661.7			1,767.2
Other non-current assets:
Regulatory assets, non-current	186.9			179.9			209.4			203.9
Intangible assets, net of amortization	0.9			5.0			19.7			22.7
Other deferred assets	23.2			20.7			13.5			16.6
Total other non-current assets	211.0			205.6			242.6			243.2

Total assets	$	2,950.4		$	3,324.7		$	2,174.3		$	2,419.2

LIABILITIES AND SHAREHOLDER'S EQUITY
LIABILITIES AND SHAREHOLDER'S DEFICIT
Current liabilities:
Current portion of long-term debt (Note 6)	$	79.2		$	572.8
Current portion of long-term debt (Note 7)							$	29.7		$	29.7
Short-term debt							65.0			—
Accounts payable	87.4			97.5			61.3			113.9
Accrued taxes	186.7			142.4			169.9			185.1
Accrued interest	35.5			21.4			26.8			17.7
Security deposits	14.6			15.2			16.4			15.2
Regulatory liabilities, current	44.7			24.4			20.0			33.7
Insurance and claims costs	5.9			5.9			5.4			5.4
Other current liabilities	76.1			54.5			31.5			50.2
Deposit received on sale of DPLER	—			75.5
Liabilities held for sale, current	—			1.6
Liabilities held for sale - current (Note 13)							7.0			—
Total current liabilities	530.1			1,011.2			433.0			450.9

Non-current liabilities:
Long-term debt (Note 6)	1,834.8			1,420.5
Long-term debt (Note 7)							1,712.2			1,828.7
Deferred taxes	463.1			568.7			254.6			252.4
Taxes payable	1.6			84.1			3.6			84.6
Regulatory liabilities, non-current	129.9			127.0			134.5			130.4
Pension, retiree and other benefits	80.5			87.1			100.7			101.6
Asset retirement obligations							132.5			138.8
Other deferred credits	87.5			88.3			14.0			19.4
Total non-current liabilities	2,597.4			2,375.7			2,352.1			2,555.9

Redeemable preferred stock of subsidiary (Note 9)	—			18.4

Commitments and contingencies (Note 10)

Common shareholder's equity:
Common shareholder's deficit
Common stock:
1,500 shares authorized; 1 share issued and outstanding at September 30, 2016 and December 31, 2015	—			—
1,500 shares authorized; 1 share issued and outstanding at September 30, 2017 and December 31, 2016							—			—
Other paid-in capital	2,232.8			2,237.7			2,233.3			2,233.0
Accumulated other comprehensive income	15.7			17.4			6.1			0.3
Accumulated deficit	(2,425.6		)	(2,335.7		)	(2,850.2		)	(2,820.9		)
Total common shareholder's equity	(177.1		)	(80.6		)
Total common shareholder's deficit							(610.8		)	(587.6		)

Total liabilities and shareholder's equity	$	2,950.4		$	3,324.7
Total liabilities and shareholder's deficit							$	2,174.3		$	2,419.2

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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													DPL INC.	CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine months ended September 30,						Nine months ended September 30,
$ in millions	2016			2015			2017			2016
Cash flows from operating activities:
Net income / (loss)	$	(89.9	)	$	59.0
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Net loss							$	(29.3	)	$	(89.9	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation and amortization	100.3			104.1			81.8			100.3
Amortization of debt market value adjustments	0.1			(1.1		)
Charge for early redemption of debt	3.1			2.1			3.3			3.1
Deferred income taxes	(101.4		)	(20.5		)	(3.5		)	(101.4		)
Fixed-asset impairment	235.5			—			66.4			235.5
Gain on sale of business	(49.2		)	—			—			(49.2		)
Loss on asset disposal							15.9			0.1
Changes in certain assets and liabilities:
Accounts receivable	23.6			48.8			15.8			23.6
Inventories	29.1			3.1			9.5			29.1
Prepaid taxes	0.2			(0.6		)	—			0.2
Taxes applicable to subsequent years	61.5			58.2			61.4			61.5
Deferred regulatory costs, net	19.5			27.6			(6.5		)	19.5
Accounts payable	(10.2		)	(15.9		)	(46.4		)	(10.2		)
Accrued taxes payable	(34.2		)	(39.2		)	(93.5		)	(34.2		)
Accrued interest payable	13.9			3.7			8.8			13.9
Security deposits	(0.6		)	19.4			1.1			(0.6		)
Pension, retiree and other benefits	(2.2		)	1.0			3.8			(2.2		)
Other	(0.5		)	10.7			(6.9		)	(0.5		)
Net cash provided by operating activities	198.6			260.4			81.7			198.6
Cash flows from investing activities:
Capital expenditures	(109.8		)	(93.5		)	(95.6		)	(109.8		)
Proceeds from sale of business	75.5			1.3			—			75.5
Insurance proceeds	5.2			—			12.6			5.2
Purchase of renewable energy credits	(0.3		)	(0.6		)	(0.1		)	(0.3		)
Decrease in restricted cash	5.5			3.2			27.0			5.5
Other investing activities, net	0.8			0.4			0.3			0.8
Net cash used in investing activities	(23.1		)	(89.2		)	(55.8		)	(23.1		)
Cash flows from financing activities:
Payments of deferred financing costs	(8.0		)	(5.6		)	—			(8.0		)
Issuance of long-term debt, net of discount	442.8			325.0			—			442.8
Retirement of long-term debt	(520.8		)	(474.5		)	(122.1		)	(520.8		)
Borrowings from revolving credit facilities	—			70.0			80.0			—
Repayment of borrowings from revolving credit facilities	—			(60.0		)	(15.0		)	—
Other financing activities, net	(0.1		)	(0.1		)	—			(0.1		)
Net cash used in financing activities	(86.1		)	(145.2		)	(57.1		)	(86.1		)
Cash and cash equivalents:
Net change	89.4			26.0			(31.2		)	89.4
Balance at beginning of period	32.4			17.0			54.6			32.4
Cash and cash equivalents at end of period	$	121.8		$	43.0		$	23.4		$	121.8
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	61.1		$	77.3		$	69.0		$	61.1
Income taxes paid / (refunded), net	$	0.3		$	0.8		$	—		$	0.3
Non-cash financing and investing activities:
Accruals for capital expenditures	$	15.9		$	12.6		$	9.2		$	15.9

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’s~~DPL ~~one~~has two reportable segments: the Transmission and Distribution segment isand the ~~Utility segment, comprised of its~~ ~~DP&L~~ ~~subsidiary. DPLER, which was~~ ~~DPL's~~ ~~competitive retail segment, was sold January 1, 2016.~~Generation segment. See Note 1211 – 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~~retail transmission and ~~transmission retail~~distribution services are still regulated. DP&L has the exclusive right to provide such ~~distribution~~transmission and ~~transmission~~distribution services to approximately ~~518,000~~520,000 customers located in West Central Ohio. Additionally, DP&L ~~offers~~procures retail SSO electric service toon behalf of residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. As of September 30, 2017, DP&L ~~owns~~owned undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. As of October 1, 2017, the DP&L-owned generating facilities ~~all~~were transferred to AES Ohio Generation, an affiliate of ~~which are included in the financial statements at amortized cost.~~DP&L and wholly-owned subsidiary of DPL, through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. Also, Stuart Station Unit 1 was retired on October 1, 2017. 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, health care, data management, manufacturing and defense. DP&L's distribution sales reflect the general economic conditions, seasonal weather patterns, ~~retail competition in our service territory~~the proliferation of energy efficiency and distributed renewable resources and the market price of electricity. From January 1, 2016 through September 30, 2017, DP&L ~~sells~~sold 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. AES Ohio Generation, as of September 30, 2017, owned and operated certain peaking generating facilities, and, as of October 1, 2017, owns those facilities plus additional coal-fired and peaking facilities previously owned by DP&L. AES Ohio Generation sells all of its energy and capacity into the wholesale market. 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.~~regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.

DPL and its subsidiaries employed ~~1,171~~1,074 people as of September 30, ~~2016,~~2017, of which ~~1,163~~1,065 were employed by DP&L. As part of Generation Separation on October 1, 2017, DP&L generation employees became employees of AES Ohio Generation. Approximately ~~62%~~61% of all ~~DPL~~DP&L and AES Ohio Generation employees are under a collective bargaining agreement that ~~expires~~was set to expire on October 31, 2017. The Company and the union representing these employees have agreed to extend the current agreement through January 31, 2018, while continuing to negotiate a new agreement. We are unable to determine what impact a new agreement may have on our operations.

Financial Statement Presentation

DPL’s Condensed Consolidated Financial Statements include the accounts of DPL and its wholly-owned subsidiaries except for DPL Capital Trust II, which is not consolidated, consistent with the provisions of GAAP. As of September 30, 2017, DP&L ~~has~~had 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~~the lower of depreciated historical cost ~~which was adjusted to~~or fair value, ~~at the date of the Merger for~~ ~~DPL~~.if impaired. Operating revenues and expenses of

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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.

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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.~~2016.

In the opinion of our management, the Condensed Consolidated Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of September 30, ~~2016;~~2017; our results of operations for the three and nine months ended September 30, ~~2016~~2017 and ~~2015~~2016 and our cash flows for the nine months ended September 30, ~~2016~~2017 and ~~2015.~~2016. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including, but not limited to, seasonal weather variations, the timing of outages of EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, ~~2016~~2017 may not be indicative of our results that will be realized for the full year ending December 31, ~~2016.~~2017.

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

~~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, 2017 and 2016 ~~and 2015~~ were ~~$14.4~~$13.0 million and ~~$13.0~~$14.4 million, respectively. The amounts of such taxes collected for the nine months ended September 30, 2017 and 2016 ~~and 2015~~ were ~~$38.9~~$36.9 million and ~~$38.5~~$38.9 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~~2016-09, Compensation - ~~Imputation of Interest (Subtopic 835-30)~~Stock Compensation (Topic 718): ~~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~~Improvements 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)~~Employee Share-Based Payment Accounting	The standard simplifies the ~~presentation~~following aspects of ~~debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in~~accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the ~~balance sheet~~statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as ~~a direct deduction from the carrying amount~~either equity or liabilities and classification of ~~that debt liability, consistent with debt discounts.~~employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and ~~measurement guidance for debt issuance costs~~tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are ~~not affected by the standard. Transition method: retrospective.~~recognized was adopted on a modified retrospective basis.	January 1, ~~2016~~2017.	~~Deferred financing costs~~The primary effect 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~~adoption was the ~~related debt liabilities.~~recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. The adoption of this standard did not have a material impact on the consolidated financial statements.

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Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
~~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~~2017-12, Derivatives and Hedging (Topic ~~810)~~815): ~~Interest Held through Related Parties That Are under Common Control~~Targeted improvements to Accounting for Hedging Activities	The standard updates the hedge accounting model in ASC 815 to expand the ability to hedge risk, reduce complexity and ease certain documentation and assessment requirements. It also eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. Transition method: modified retrospective approach and prospective for presentation and disclosures.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements and if we would early adopt it.
2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities	This standard ~~amends~~shortens the ~~evaluation~~period of ~~whether a reporting entity is~~amortization of 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. premium on certain callable debt securities to the earliest call date. Transition method: ~~retrospectively.~~modified retrospective.	January 1, ~~2017~~ 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost	This standard changes the presentation of non-service cost expense associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in capitalization.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2017-05, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Topic 610-20)	This standard clarifies the scope and application of ASC 610-20 on the sale, transfer, and derecognition of nonfinancial assets and in substance nonfinancial assets to non-customers, including partial sales. It also clarifies that the derecognition of businesses is under scope of ASC 810. Transition method: full or modified retrospective we are in the process of identifying contracts that would not be completed as of January 1, 2018. Based on the assessment of contracts already executed as of the balance sheet date, the contracts that may require any type of assessment under the new standard are limited.	January 1, 2018.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements. We will adopt the standard on January 1, 2018 and plan to use the modified retrospective approach.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business	This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. Transition method: prospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)	This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity ~~recognizes~~recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified ~~retrospective method.~~retrospective.	January 1, ~~2018~~ 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~~ 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)	This standard requires lessees to recognize assets and liabilities for most leases but recognize expenses in a manner similar to today’s accounting. For lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The 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. guidance also eliminates today’s real estate-specific provisions. Transition method: modified retrospective ~~approach with certain practical expedients.~~at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017). We have established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use asset and related liability. The implementation team is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard.	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~~ We intend to adopt 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.~~2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05, 2017-13 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 implementationSee discussion 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.ASUs below.	January 1, ~~2018 (deferred by ASU No. 2015-14). Earlier application is permitted only as of~~2018.	We will adopt the standard on January 1, ~~2017.~~	~~We are currently evaluating~~2018; see below for the evaluation of the impact of ~~adopting~~its adoption on the ~~standard on our~~ consolidated financial statements.

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

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

Given the complexity and diversity of our non-regulated arrangements, we are assessing the standard on a contract-by-contract basis and are in the process of completing the contract assessments by applying interpretations reached during 2017 on key issues. These issues include the application of the practical expedient for measuring progress towards satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services and how to allocate variable consideration to one or more, but not all, distinct goods or services promised in a series of distinct goods or services that forms part of a single performance obligation. We will continue our work to complete the assessment of the full population of contracts and determine the overall impact to the consolidated financial statements.

The standard requires retrospective application and allows either a full retrospective adoption in which all periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. Although we had previously been working toward adopting the standard using the full retrospective method, given the limited situations where revenue recognized under ASC 606 differs from that recognized under ASC 605, we now expect to use the modified retrospective approach. However, we will continue to assess this conclusion which is dependent on the final impact to the financial statements.

We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group activity, as we finalize our accounting policy on these and other industry specific interpretative issues which is expected in 2017.

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Note 2 – Supplemental Financial Information

Accounts receivable and Inventories are as follows at September 30, ~~2016~~2017 and December 31, ~~2015:~~2016:

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.~~



	September 30,			December 31,
$ in millions	2017			2016
Accounts receivable, net:
Unbilled revenue	$	14.4		$	43.0
Customer receivables	74.2			73.9
Amounts due from partners in jointly-owned plants	17.8			12.7
Other	6.1			6.7
Provision for uncollectible accounts	(1.1		)	(1.2		)
Total accounts receivable, net	$	111.4		$	135.1

Inventories, at average cost:
Fuel and limestone	$	16.8		$	38.9
Plant materials and supplies	10.9			36.6
Other	1.0			1.7
Total inventories, at average cost	$	28.7		$	77.2

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~~2017 and ~~2015~~2016 are as follows:


Details about Accumulated Other Comprehensive Income / (Loss) components		Affected line item in the Condensed Consolidated Statements of Operations	Three months ended						Nine months ended							Affected line item in the Condensed Consolidated Statements of Operations	Three months ended						Nine months ended
			September 30,						September 30,								September 30,						September 30,
$ in millions			2016			2015			2016			2015					2017			2016			2017			2016
Gains and losses on cash flow hedges (Note 5):
Gains and losses on Available-for-sale securities activity (Note 5):															Gains and losses on Available-for-sale securities activity (Note 5):
																Other income	$	—		$	—		$	(0.1	)	$	—

Gains and losses on cash flow hedges (Note 6):															Gains and losses on cash flow hedges (Note 6):
		Interest expense	$	(0.2	)	$	(0.2	)	$	(0.7	)	$	(0.7	)		Interest expense	(0.2		)	(0.2		)	(0.8		)	(0.7		)
		Revenue	(9.3		)	(3.8		)	(46.6		)	(7.0		)		Revenue	(4.2		)	(9.3		)	(12.5		)	(46.6		)
		Purchased power	1.0			0.9			9.1			2.7				Purchased power	0.7			1.0			4.0			9.1
		Total before income taxes	(8.5		)	(3.1		)	(38.2		)	(5.0		)		Total before income taxes	(3.7		)	(8.5		)	(9.3		)	(38.2		)
		Tax expense	3.0			1.1			13.8			1.6				Tax expense	1.3			3.0			3.3			13.8
		Net of income taxes	(5.5		)	(2.0		)	(24.4		)	(3.4		)		Net of income taxes	(2.4		)	(5.5		)	(6.0		)	(24.4		)
Amortization of defined benefit pension items (Note 8):

Amortization of defined benefit pension items (Note 9):															Amortization of defined benefit pension items (Note 9):
		Operation and maintenance	—			0.1			0.2			0.3				Operation and maintenance	—			—			1.4			0.2
		Tax benefit	—			—			(0.1		)	(0.4		)		Tax benefit	—			—			(0.5		)	(0.1		)
		Net of income taxes	—			0.1			0.1			(0.1		)		Net of income taxes	—			—			0.9			0.1

Total reclassifications for the period, net of income taxes	Total reclassifications for the period, net of income taxes		$	(5.5	)	$	(1.9	)	$	(24.3	)	$	(3.5	)	Total reclassifications for the period, net of income taxes		$	(2.4	)	$	(5.5	)	$	(5.2	)	$	(24.3	)

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The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months ended September 30, ~~2016~~2017 are as follows:


$ in millions	Gains / (losses) on available-for-sale securities		Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total			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
Balance at January 1, 2017												$	0.6		$	13.1		$	(13.4	)	$	0.3

Other comprehensive income before reclassifications	0.2		22.4			—			22.6
Other comprehensive income / (loss) before reclassifications												0.4			12.1			(1.5		)	11.0
Amounts reclassified from accumulated other comprehensive income / (loss)	—		(24.4		)	0.1			(24.3		)	(0.1		)	(6.0		)	0.9			(5.2		)
Net current period other comprehensive income / (loss)	0.2		(2.0		)	0.1			(1.7		)	0.3			6.1			(0.6		)	5.8

Balance September 30, 2016	$	0.6	$	24.7		$	(9.6	)	$	15.7
Balance at September 30, 2017												$	0.9		$	19.2		$	(14.0	)	$	6.1

Note 3 – Regulatory Matters

~~Ohio law requires~~In January 2017, DP&L filed a settlement in its ESP 3 case and filed an amended stipulation on March 13, 2017, which was subject to approval by the PUCO. A final decision was issued by the PUCO on October 20, 2017, modifying and adopting the amended stipulation and recommendation. The ESP establishes DP&L's framework for providing retail service on a going forward basis including rate structures, non-bypassable charges and other specific rate recovery true-up mechanisms. The signatory parties agreed to a six-year settlement that ~~all Ohio distribution utilities file either an ESP or MRO~~provides a framework for energy rates and defines components which include, but are not limited to, ~~establish~~the following:

Bypassable standard offer energy rates for ~~SSO service. Although it~~ DP&L’s customers based on competitive bid auctions;

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

The establishment of a non-bypassable Distribution Investment Rider to recover incremental distribution capital investments, the amount of which is to be established in ~~effect since January 2014, on June 20, 2016,~~a separate DP&L distribution rate case

A non-bypassable Reconciliation Rider permitting DP&L to defer, recover or credit the ~~Supreme Court of Ohio (Court) issued an opinion in the appeal~~net proceeds from selling energy and capacity received as part of DP&L’s investment in OVEC and DP&L's OVEC related costs;

Implementation by DP&L of a Smart Grid Rider, Economic Development Rider, Economic Development Fund, Regulatory Compliance Rider and certain other new, or changes to existing, rates, riders and competitive retail market enhancements, with tariffs consistent with the order to be effective November 1, 2017;

A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants, with all sales proceeds used to pay debt of DPL and DP&L; and

Restrictions on DPL making dividend or tax sharing payments; and

Various other riders and competitive retail market enhancements.

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

DP&L’sESP 2 ~~which~~ had been approved by the PUCO for the years ~~2014-2016~~2014 - 2016, and ~~which, among other matters,~~ permitted DP&L to collect a non-bypassable service stability rider equal to ~~approximately $9.2~~$110.0 million per ~~month~~year for each of those years and required DP&L to ~~legally separate its~~conduct competitive bid auctions to procure 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~~supply for SSO service. The Ohio Supreme Court in a June 2016 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~~.reversed. In view of that reversal, ~~on July 27, 2016~~ DP&L filed a motion to withdraw its ESP 2 and implement rates consistent with those in effect prior to 2014. The PUCO approved DP&L’s withdrawal of ESP 2 and implementation plans. Those rates were in effect until rates approved 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 effective, November 1, 2017. In February 2017, several parties appealed the PUCO orders that approved both the withdrawal and ~~effective. The~~the implementation plans to the Ohio Supreme Court. Those appeals are pending, and the outcome and potential financial 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~~appeals cannot 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 determined~~DP&L's~~ ~~application, our results of operations, financial condition and cash flows could be materially impacted.~~

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at this time. In July 2017, the Office of the Ohio Consumers Counsel filed a motion with the Ohio Supreme Court seeking to stay collection of the reinstated prior rates while the appeals are pending. That stay was denied by the Ohio Supreme Court in September 2017.

DP&L is subject to a SEET threshold and is required to apply general rules for calculating earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings during a given calendar year. The ESP 3 maintains DP&L’s return on equity SEET threshold at 12% and provides that DMR amounts are excluded from the SEET calculation. A stipulation was reached with the PUCO staff agreeing that DP&L did not exceed the SEET threshold for 2015, which was approved by the PUCO on September 6, 2017. On May 15, 2017, DP&L filed its application to demonstrate that it did not have significantly excessive earnings for calendar year 2016. That case is still pending. In future years, the SEET could have a material effect on results of operations, financial condition and cash flows.

Note 4 – Property, Plant and Equipment

Coal-fired facilities

As of September 30, 2017, DP&L and certain other Ohio utilities had undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. DP&L’s share of the operations of such facilities is included within the corresponding line in the Condensed Consolidated Statements of Operations, and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Consolidated Balance Sheets, except for amounts related to Miami Fort and Zimmer, which are classified as Held for Sale, as described below. Each co-owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.

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



	DP&L Share		DPL Carrying Value
	Ownership (%)	Summer Production Capacity (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)
Jointly-owned production units
Conesville - Unit 4	16.5	129	$	0.5	$	0.5	$	2.3
Killen - Unit 2	67.0	402	8.5		4.1		—
Miami Fort - Units 7 and 8 (a)	36.0	368	31.3		3.3		5.1
Stuart - Units 2 through 4	35.0	606	0.7		0.7		—
Zimmer - Unit 1 (a)	28.1	371	21.3		15.3		5.2
Transmission (at varying percentages)			43.2		11.5		—
Total		1,876	$	105.5	$	35.4	$	12.6


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

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

On January 10, 2017, a high-pressure feedwater heater shell failed on Unit 1 at the J.M. Stuart station. As a result, $6.4 million of net book value was written off, resulting in a $3.2 million loss on disposal, net of accrued insurance recoveries, which was recorded during the first quarter of 2017. This loss was reversed during the second quarter of 2017 due to additional accrued insurance recoveries. This unit was retired on October 1, 2017. Accordingly, the 202 MWs of capacity associated with Stuart Unit 1 have been removed from the table above.

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

On October 1, 2017, Generation Separation was completed and the coal-fired electric generating facilities described above were transferred to AES Ohio Generation. The portion of the co-owned transmission facilities owned by DP&L remains owned by DP&L.

AROs

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

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

Changes in the Liability for Generation AROs



$ in millions
Balance at January 1, 2017	$	138.8
Additions	0.1
Revisions to cash flow and timing estimates	(4.8		)
Accretion expense	2.9
Settlements	(0.1		)
Reclassified to Liabilities held for sale	(4.4		)
Balance at September 30, 2017	$	132.5

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

Note 5 – Fair Value

The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other methods exist. The value of our financial instruments represents our best estimates of the fair value, which may not be the value realized in the future.

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The following table presents the fair value, carrying value and cost of our non-derivative instruments at September 30, ~~2016~~2017 and December 31, ~~2015.~~2016. Information about the fair value of our derivative instruments can be found in Note 56 – Derivative Instruments and Hedging Activities.


	September 30, 2016				December 31, 2015				September 30, 2017				December 31, 2016
$ in millions	Cost		Fair Value		Cost		Fair Value		Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.3	$	0.3	$	0.2	$	0.2	$	0.4	$	0.4	$	0.4	$	0.4
Equity securities	2.4		3.4		3.0		3.8		2.6		4.1		2.4		3.4
Debt securities	4.5		4.5		4.4		4.3		4.2		4.3		4.4		4.4
Hedge funds	0.2		0.2		0.4		0.4		0.1		0.1		—		0.1
Real estate	0.3		0.3		0.3		0.3		—		—		0.3		0.3
Tangible assets									0.1		0.1		0.1		0.1
Total Assets	$	7.7	$	8.7	$	8.3	$	9.0	$	7.4	$	9.0	$	7.6	$	8.7

	Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Debt	$	1,914.0	$	1,969.4	$	1,993.3	$	1,975.3
Long-term debt (a)									$	1,741.6	$	1,843.8	$	1,858.0	$	1,907.7


(a)	Amounts exclude immaterial capital lease obligations

These financial instruments are not subject to master netting agreements or collateral requirements and as such are presented in the Condensed Consolidated Balance Sheet at their gross fair value, except for ~~Debt,~~Long-term debt, which is presented at amortized carrying value.

~~Debt~~Fair Value Hierarchy

~~Unrealized gains~~Fair value is defined as the price that would be received for an asset or ~~losses~~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 ~~recognized~~active); or

Level 3 (unobservable inputs) reflecting management’s own assumptions about the inputs used in pricing the asset or liability).

Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.

We did not have any transfers of the fair values of our financial ~~statements as debt is presented at cost, net~~instruments between Level 1, Level 2 or Level 3 of ~~unamortized premium~~the fair value hierarchy during the nine months ended September 30, 2017 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.~~2016.

Master Trust Assets

DP&L established a Master ~~Trusts~~Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans and these assets are not used for general operating purposes. 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~~$1.5 million ($0.9 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2017 and $1.0 million ($0.6 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at ~~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.~~2016.

During the nine months ended September 30, ~~2016, $2.3~~2017, $0.8 million ($~~1.5~~0.6 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings. An immaterial

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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~~Long-term debt

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~~debt is based on current public market prices for ~~similar assets~~disclosure purposes only. Unrealized gains or ~~liabilities or quoted prices in markets that~~losses are not ~~active);~~recognized in the financial statements as long-term debt is presented at cost, net of unamortized premium or

~~Level 3 (unobservable inputs).~~

~~Valuations of assets~~ discount and ~~liabilities reflect~~unamortized deferred financing costs in the ~~value of~~financial statements. The long-term debt amounts include the ~~instrument including~~current portion payable in the ~~values associated with counterparty risk. We include our own credit risk~~next twelve months 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.~~maturities that range from 2019 to 2061.

The fair value of assets and liabilities at September 30, ~~2016~~2017 and December 31, ~~2015~~2016 and the respective category within the fair value hierarchy for DPL was determined as follows:

																	Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3				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		Fair value at September 30, 2017 (a)		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	—	$	—	$	0.4	$	0.4	$	—	$	—
Equity securities	3.4		—		3.4		—		4.1		—		4.1		—
Debt securities	4.5		—		4.5		—		4.3		—		4.3		—
Hedge funds	0.2		—		0.2		—		0.1		—		0.1		—
Real estate	0.3		—		0.3		—
Tangible assets									0.1		—		0.1		—
Total Master Trust assets	8.7		0.3		8.4		—		9.0		0.4		8.6		—
Derivative Assets
FTRs	0.1		—		—		0.1
Forward power contracts	33.1		—		32.5		0.6		10.8		—		10.8		—
Interest rate hedges									0.9		—		0.9		—
Natural gas									—		—		—		—
Total Derivative assets	33.2		—		32.5		0.7		11.7		—		11.7		—

Total Assets	$	41.9	$	0.3	$	40.9	$	0.7	$	20.7	$	0.4	$	20.3	$	—

Liabilities
Derivative Liabilities
Interest rate hedges									$	—	$	—	$	—	$	—
FTRs									0.5		—		—		0.5
Natural gas futures									0.8		0.8		—		—
Forward power contracts	30.9		—		25.9		5.0		8.1		—		8.1		—
Total Derivative liabilities	30.9		—		25.9		5.0		9.4		0.8		8.1		0.5
Debt	1,969.4		—		1,951.4		18.0
Long-term debt (b)									1,843.8		—		1,825.9		17.9

Total Liabilities	$	2,000.3	$	—	$	1,977.3	$	23.0	$	1,853.2	$	0.8	$	1,834.0	$	18.4


(a)	Includes credit valuation adjustment


(b)	Amounts exclude immaterial capital lease obligations

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																	Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3				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		Fair value at December 31, 2016 (a)		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.2	$	0.2	$	—	$	—	$	0.4	$	0.4	$	—	$	—
Equity securities	3.8		—		3.8		—		3.4		—		3.4		—
Debt securities	4.3		—		4.3		—		4.4		—		4.4		—
Hedge funds	0.4		—		0.4		—		0.1		—		0.1		—
Real estate	0.3		—		0.3		—		0.3		—		0.3		—
Tangible assets									0.1		—		0.1		—
Total Master Trust assets	9.0		0.2		8.8		—		8.7		0.4		8.3		—
Derivative assets
Forward power contracts	30.5		—		30.5		—		19.5		—		19.5		—
Interest rate hedges									1.2		—		1.2		—
FTRs	0.2		—		—		0.2		0.1		—		—		0.1
Total Derivative assets	30.7		—		30.5		0.2		20.8		—		20.7		0.1

Total Assets	$	39.7	$	0.2	$	39.3	$	0.2	$	29.5	$	0.4	$	29.0	$	0.1

Liabilities
Derivative liabilities
FTRs	$	0.5	$	—	$	—	0.5
Interest rate hedges									$	0.7	$	—	$	0.7	$	—
Forward power contracts	27.0		—		23.9		3.1		28.5		—		26.0		2.5
Total Derivative liabilities	27.5		—		23.9		3.6		29.2		—		26.7		2.5
Debt	1,975.3		—		1,957.2		18.1
Long-term debt (b)									1,907.7		—		1,889.7		18.0

Total Liabilities	$	2,002.8	$	—	$	1,981.1	$	21.7	$	1,936.9	$	—	$	1,916.4	$	20.5


(a)	Includes credit valuation adjustment


(b)	Amounts exclude immaterial capital lease obligations

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

Level 1 inputs are used for derivative contracts such as ~~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~~NAV per unit.

Level 3 inputs such as FTRs are considered a Level 3 input because the monthly auctions are considered inactive. Other Level 3 inputs include the credit valuation adjustment on some of the forward power contracts and forward power contracts in less active markets. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.

Approximately ~~93%~~86% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Our long-term debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. As the Wright-Patterson Air Force Base ~~loan~~note is not publicly traded, fair value is assumed to equal carrying value. These fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures are not presented since our long-term debt is not recorded at fair value.

~~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. As a result of changes in our estimates of costs to be incurred for our AROs, we decreased our AROs by $4.8 million in the first nine months of 2017. AROs for ash ponds, asbestos, ash landfills, river structures and underground storage tanks decreased by a net amount of $1.9 million and 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, 2017 and 2016, respectively. In addition, there was a $4.4 million decrease in the ARO liability during the nine months ended September 30, 2017 related to AROs at Miami Fort and Zimmer being reclassified to Liabilities held for sale - current.

On March 17, 2017, the Board of Directors of DP&L approved the retirement of the DP&L operated and co-owned Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine (collectively, the “Facilities”) on or before June 1, 2018, and the co-owners of the Facilities agreed with DP&L to proceed with this plan of retirement. As a result, we performed a long-lived asset impairment analysis during the first quarter of 2017 and determined that the carrying amounts of the Facilities were not recoverable. See Note 14 – Fixed-asset Impairments.

A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for Killen and certain DP&L peaking generating facilities. As a result, we performed a long-lived asset impairment analysis during the second quarter of 2016 and ~~2015, respectively.~~determined that the carrying amount of these assets were not recoverable. See Note 14 – Fixed-asset Impairments.

When evaluating impairment of long-lived assets, we measure fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount. The following table summarizes Long-lived assets measured at fair value on a non-recurring basis during the ~~nine months ended September 30, 2016~~periods and their level within the fair value ~~hierarchy (there were no impairments during the nine months ended September 30, 2015):~~hierarchy:


											Carrying		Fair Value						Gross
											Amount ^(b)		Level 1		Level 2		Level 3		Loss
$ in millions	Nine months ended September 30, 2016										Nine months ended September 30, 2017
Assets
Long-lived assets ^(a)
Stuart											$	42.4	$	—	$	—	$	3.3	$	39.1
Killen											$	35.2	$	—	$	—	$	7.9	$	27.3
																			$	66.4
	Carrying		Fair Value						Gross
	Amount ^(b)		Level 1		Level 2		Level 3		Loss		Nine months ended September 30, 2016
Assets
Long-lived assets ^(a)
DP&L (Killen)	$	315.1	$	—	$	—	$	84.3	$	230.8
DP&L (peaking facilities)	$	9.9	$	—	$	—	$	5.2	$	4.7
Killen											$	315.1	$	—	$	—	$	84.3	$	230.8
DP&L peaking facilities											$	9.9	$	—	$	—	$	5.2	$	4.7
																			$	235.5

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

(b)Carrying amount at date of valuation

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The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the nine months ended September 30, 2017:



$ in millions	Fair value		Valuation technique	Unobservable input	Weighted average
Long-lived assets held and used:
Stuart	$	3.3	Discounted cash flow	Pre-tax operating margin (through remaining life)	10.0	%
				Weighted-average cost of capital	7.0	%

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

The 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)

Fair value

Valuation technique

Unobservable input

Weighted average

Long-lived assets held and used:

DP&L (Killen)

84.3

Discounted cash flow

Annual revenue growth

-11% to 13% (2%)

Killen

84.3

Discounted cash flow

Annual revenue growth

-11.0% to 13.0% (2.0%)

Annual pre-tax operating margin

-50% to 57% (6%)

Annual pre-tax operating margin

-50.0% to 67.0% (6.0%)

Weighted-average cost of capital

11%

Weighted-average cost of capital

11.0%

DP&L (peaking facilities)

5.2

Discounted cash flow

Annual revenue growth

-22% to 17% (-3%)

DP&L peaking facilities

5.2

Discounted cash flow

Annual revenue growth

-22.0% to 17.0% (-3.0%)

Annual pre-tax operating margin

-29% to 24% (-4%)

Annual pre-tax operating margin

-29.0% to 24.0% (-4.0%)

Weighted-average cost of capital

7.0%

Note 56 – Derivative Instruments and Hedging Activities

In the normal course of business, DPL enters into various financial ~~arrangements,~~instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for ~~commodities.~~commodities and interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as ~~normal purchase/normal sale,~~ cash flow hedges ~~or marked to market each reporting period.~~if they qualify under FASC 815 for accounting purposes.

~~Table of Contents~~

At September 30, ~~2016,~~2017, ~~DPL~~DPL's ~~had the following outstanding~~ derivative ~~instruments:~~instruments were as follows:


Commodity	Accounting Treatment ^(a)	Unit	Purchases (in thousands)	Sales (in thousands)		Net Purchases/ (Sales) (in thousands)		Accounting Treatment ^(a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	2.8	—		2.8		Not designated	MWh	3.4		—			3.4
Natural Gas Futures	Not designated	Dths	—	(20.0	)	(20.0	)
Natural gas futures								Not designated	Dths	6,625.0		(390.0		)	6,235.0
Forward power contracts	Designated	MWh	607.6	(10,699.9	)	(10,092.3	)	Designated	MWh	649.0		(2,478.9		)	(1,829.9		)
Forward power contracts	Not designated	MWh	2,866.9	(2,393.1	)	473.8		Not designated	MWh	1,082.8		(1,060.0		)	22.8
Interest rate swaps								Designated	USD	$	200,000.0	$	—		$	200,000.0

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

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At December 31, ~~2015,~~2016, ~~DPL~~DPL's ~~had the following outstanding~~ derivative ~~instruments:~~instruments were as follows:


Commodity	Accounting Treatment ^(a)	Unit	Purchases (in thousands)	Sales (in thousands)		Net Purchases/ (Sales) (in thousands)		Accounting Treatment ^(a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	10.2	—		10.2		Not designated	MWh	2.3		—			2.3
Natural gas futures								Not designated	Dths	1,590.0		—			1,590.0
Forward power contracts	Designated	MWh	1,676.7	(7,795.8	)	(6,119.1	)	Designated	MWh	342.9		(9,974.5		)	(9,631.6		)
Forward power contracts	Not designated	MWh	5,049.9	(1,663.0	)	3,386.9		Not designated	MWh	2,568.3		(2,020.9		)	547.4
Interest rate swaps								Designated	USD	$	200,000.0	$	—		$	200,000.0

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

Cash Flow Hedges

As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair ~~value~~values of cash flow hedges is determined by ~~observable~~current public market prices ~~available as of the balance sheet dates and~~ will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges.

We enter into forward power contracts to manage commodity price risk exposure related to our generation of electricity. We do not hedge all commodity price risk. We reclassify gains and losses on forward power contracts from AOCI into earnings in those periods in which the contracts settle.

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

We had previously entered into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. These interest rate derivative contracts were settled in the third quarter of 2013 and we continue to amortize amounts out of AOCI into interest expense.

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The following ~~table provides~~tables provide information ~~for~~ ~~DPL~~ concerning gains or losses recognized in AOCI for the cash flow hedges for the three and nine months ended September 30, ~~2016~~2017 and ~~2015:~~2016:


		Three months ended						Three months ended							Three months ended						Three months ended
		September 30, 2016						September 30, 2015							September 30, 2017						September 30, 2016
					Interest						Interest							Interest						Interest
$ in millions (net of tax)		Power			Rate Hedge			Power			Rate Hedge				Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI		$	3.4		$	17.3		$	1.1		$	17.8			$	3.0		$	17.2		$	3.4		$	17.3
Net gains associated with current period hedging transactions		9.5			—			7.8			—				1.3			0.1			9.5			—
Net gains / (losses) reclassified to earnings	Net gains / (losses) reclassified to earnings													Net gains / (losses) reclassified to earnings
Interest expense		—			(0.1		)	—			(0.1		)		—			(0.2		)	—			(0.1		)
Revenues		(6.0		)	—			(2.5		)	—				(2.7		)	—			(6.0		)	—
Purchased power		0.6			—			0.6			—				0.5			—			0.6			—
Ending accumulated derivative gains in AOCI		$	7.5		$	17.2		$	7.0		$	17.7			$	2.1		$	17.1		$	7.5		$	17.2

		Nine months ended						Nine months ended							Nine months ended						Nine months ended
		September 30, 2016						September 30, 2015							September 30, 2017						September 30, 2016
					Interest						Interest							Interest						Interest
$ in millions (net of tax)		Power			Rate Hedge			Power			Rate Hedge				Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI		$	9.2		$	17.5		$	0.2		$	18.3
Beginning accumulated derivative gains / (losses) in AOCI															$	(4.3	)	$	17.4		$	9.2		$	17.5
Net gains associated with current period hedging transactions		22.4			—			9.6			—				11.9			0.2			22.4			—
Net gains / (losses) reclassified to earnings	Net gains / (losses) reclassified to earnings													Net gains / (losses) reclassified to earnings
Interest expense		—			(0.3		)	—			(0.6		)		—			(0.5		)	—			(0.3		)
Revenues		(30.0		)	—			(4.5		)	—				(8.1		)	—			(30.0		)	—
Purchased power		5.9			—			1.7			—				2.6			—			5.9			—
Ending accumulated derivative gains in AOCI		$	7.5		$	17.2		$	7.0		$	17.7			$	2.1		$	17.1		$	7.5		$	17.2

Portion expected to be reclassified to earnings in the next twelve months ^(a)		$	—		$	0.6									$	1.5		$	(0.4	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		15			0										6			37

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

Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented.

Derivatives not designated as hedges

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchase and normal sales scope exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the Condensed Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as “MTM accounting.” Contracts we enter into as part of our risk management program may be settled financially, by physical delivery, or net settled with the counterparty. FTRs, ~~heating oil futures,~~ natural gas futures, and certain forward power contracts are currently marked to market.

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

~~Regulatory Assets and Liabilities~~

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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~~2017 and ~~2015:~~2016:

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 )

~~Table of Contents~~


For the nine months ended September 30, 2015
For the three months ended September 30, 2017																	For the three months ended September 30, 2017
$ in millions		Heating Oil			FTRs			Power			Natural Gas			Total				FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)		$	0.4		$	0.2		$	(4.9	)	$	0.1		$	(4.2	)		$	0.2		$	(1.4	)	$	—		$	(1.2	)
Realized loss		(0.3		)	(0.1		)	(8.1		)	(0.1		)	(8.6		)
Realized gain / (loss)																		0.2			1.9			(0.2		)	1.9
Total		$	0.1		$	0.1		$	(13.0	)	$	—		$	(12.8	)		$	0.4		$	0.5		$	(0.2	)	$	0.7
Recorded on Balance Sheet: gain
Regulatory asset		$	0.1		$	—		$	—		$	—		$	0.1

Recorded in Income Statement: gain / (loss)	Recorded in Income Statement: gain / (loss)
Revenue		—			—			8.9			—			8.9
Revenues																		$	—		$	3.3		$	—		$	3.3
Purchased power		—			0.1			(21.9		)	—			(21.8		)		0.4			(2.8		)	(0.2		)	(2.6		)
Total		$	0.1		$	0.1		$	(13.0	)	$	—		$	(12.8	)		$	0.4		$	0.5		$	(0.2	)	$	0.7

For the three months ended September 30, 2016																	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 nine months ended September 30, 2017																	For the nine months ended September 30, 2017
$ in millions																		FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)																		$	(0.5	)	$	2.3		$	(0.8	)	$	1.0
Realized gain / (loss)																		0.5			(1.4		)	(0.3		)	(1.2		)
Total																		$	—		$	0.9		$	(1.1	)	$	(0.2	)

Recorded in Income Statement: gain / (loss)
Revenues																		$	—		$	(2.6	)	$	—		$	(2.6	)
Purchased power																		—			3.5			(1.1		)	2.4
Total																		$	—		$	0.9		$	(1.1	)	$	(0.2	)

For the nine months ended September 30, 2016																	For the nine months ended September 30, 2016
$ in millions																		FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)																		$	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	)

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

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

																									Fair Values of Derivative Instruments
at September 30, 2016
at September 30, 2017													at September 30, 2017
					Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets												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			Hedging Designation	Gross Fair Value as presented in the Consolidated Balance Sheets ^(a)		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)	Short-term derivative positions (presented in Other prepayments and current assets)												Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts		Designated	$	15.6	$	(13.3	)	$	—		$	2.3		Designated	$	7.0	$	(4.6	)	$	—		$	2.4
Forward power contracts		Not designated	8.7		(7.6		)	—			1.1			Not designated	3.5		(2.7		)	—			0.8
FTRs		Not designated	0.1		—			—			0.1
Natural gas futures														Not designated	—		—			—			—

Long-term derivative positions (presented in Other deferred assets)
Forward power contracts		Designated	7.4		(1.1		)	—			6.3
Interest rate swap														Designated	0.9		—			—			0.9
Natural gas futures														Not designated	—		—			—			—
Forward power contracts		Not designated	1.4		(0.7		)	—			0.7			Not designated	0.3		—			—			0.3
Total assets			$	33.2	$	(22.7	)	$	—		$	10.5			$	11.7	$	(7.3	)	$	—		$	4.4

Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts		Designated	$	16.1	$	(13.3	)	$	(2.7	)	$	0.1		Designated	$	4.6	$	(4.6	)	$	—		$	—
Interest rate swap														Designated	—		—			—			—
Forward power contracts		Not designated	12.8		(7.6		)	(2.4		)	2.8			Not designated	3.5		(2.7		)	(0.7		)	0.1
Natural gas futures														Not designated	0.8		—			(0.8		)	—
FTRs														Not designated	0.5		—			—			0.5

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
Natural gas futures														Not designated	—		—			—			—
Total liabilities			$	30.9	$	(22.7	)	$	(5.1	)	$	3.1			$	9.4	$	(7.3	)	$	(1.5	)	$	0.6

(a) includes credit valuation adjustment

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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
at December 31, 2016													at December 31, 2016
					Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets												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			Hedging Designation	Gross Fair Value as presented in the Consolidated Balance Sheets ^(a)		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)	Short-term derivative positions (presented in Other prepayments and current assets)												Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts		Designated	$	16.2	$	(7.1	)	$	—		$	9.1		Designated	$	11.0	$	(10.5	)	$	—		$	0.5
Forward power contracts		Not designated	7.3		(5.5		)	—			1.8			Not designated	6.0		(4.7		)	—			1.3
FTRs		Not designated	0.2		(0.2		)	—			—			Not designated	0.1		—			—			0.1

Long-term derivative positions (presented in Other deferred assets)
Interest rate swaps														Designated	1.2		—			—			1.2
Forward power contracts		Designated	3.0		(2.4		)	—			0.6			Designated	0.6		(0.6		)	—			—
Forward power contracts		Not designated	4.0		(2.7		)	—			1.3			Not designated	1.9		(1.0		)	—			0.9
Total assets			$	30.7	$	(17.9	)	$	—		$	12.8			$	20.8	$	(16.8	)	$	—		$	4.0

Liabilities
Short-term derivative positions (presented in Other current liabilities)	Short-term derivative positions (presented in Other current liabilities)												Short-term derivative positions (presented in Other current liabilities)
Interest rate swaps														Designated	$	0.7	$	—		$	—		$	0.7
Forward power contracts		Designated	$	7.1	$	(7.1	)	$	—		$	—		Designated	16.4		(10.5		)	(5.5		)	0.4
Forward power contracts		Not designated	14.5		(5.5		)	(8.0		)	1.0			Not designated	7.7		(4.7		)	—			3.0
FTRs		Not designated	0.5		(0.2		)	—			0.3

Long-term derivative positions (presented in Other deferred credits)	Long-term derivative positions (presented in Other deferred credits)												Long-term derivative positions (presented in Other deferred credits)
Forward power contracts		Designated	2.7		(2.4		)	—			0.3			Designated	2.4		(0.6		)	(0.8		)	1.0
Forward power contracts		Not designated	2.7		(2.7		)	—			—			Not designated	2.0		(1.0		)	—			1.0
Total liabilities			$	27.5	$	(17.9	)	$	(8.0	)	$	1.6			$	29.2	$	(16.8	)	$	(6.3	)	$	6.1

(a) includes credit valuation adjustment

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~~this threshold ~~with one counterparty to the derivative instruments~~ and ~~they~~our counterparties could request that we post collateral for our net liability position with them. As of ~~$0.9 million at~~the date of the filing of this ~~time.~~report, we have not had to post collateral with any of these counterparties.

The aggregate fair value of DPL’s commodity derivative instruments that were in a MTM loss position at September 30, ~~2016~~2017 was ~~$30.9~~$9.4 million. ~~$5.1~~$1.5 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~~$7.3 million. Since our long-term debt is below investment grade, we could have to post collateral for the remaining ~~$3.1~~$0.6 million.

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Note 67 – Long-term Debt

The following table ~~provides a summary of~~summarizes DPL's outstanding 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



	Interest		September 30,			December 31,
$ in millions	Rate	Maturity	2017			2016
Term loan - rates from 4.01% - 4.49% (a) and 4.00% - 4.01% (b)		2022	$	441.7		$	445.0
Tax-exempt First Mortgage Bonds	4.8%	2036	—			100.0
Tax-exempt First Mortgage Bonds - rates from 1.52% - 1.83% (a) and 1.29% - 1.42% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	17.9			18.0
Capital leases			0.3			0.4
Unamortized deferred financing costs			(9.9		)	(10.7		)
Unamortized long-term debt discounts and premiums, net			(2.0		)	(5.5		)
Total long-term debt at consolidated subsidiary			648.0			747.2

Bank term loan - rates from 3.02% - 3.99% (a) and 2.67% - 3.02% (b)		2020	106.3			125.0
Senior unsecured notes	6.75%	2019	200.0			200.0
Senior unsecured notes	7.25%	2021	780.0			780.0
Note to DPL Capital Trust II (c)	8.125%	2031	15.6			15.6
Unamortized deferred financing costs			(7.4		)	(8.8		)
Unamortized long-term debt discounts and premiums, net			(0.6		)	(0.6		)
Total long-term debt			1,741.9			1,858.4
Less: current portion			(29.7		)	(29.7		)
Long-term debt, net of current portion			$	1,712.2		$	1,828.7


(a)	Range of interest rates for the nine months ended September 30, ~~2016.~~2017.


(b)	Range of interest rates for the year ended December 31, ~~2015.~~2016.


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

Deferred financing costs are amortized over the remaining life of the debt using the effective interest method. Premiums or discounts ~~recognized at the date of the Merger~~on long-term debt are amortized over the remaining life of the debt using the effective interest method.

Line of credit

At September 30, 2017, DPL had $50.0 million in outstanding borrowings on its line of credit. In addition, DP&L had $15.0 million in outstanding borrowings on its line of credit.

Significant transactions

On ~~February 5, 2016, $73.0 million~~May 26, 2017, DP&L commenced a tender offer to purchase any and all of ~~DPL's~~ ~~$130.0 million 6.5% Senior Unsecured Notes Due 2016 were redeemed under~~ the ~~indenture's make-whole call provision, which allows for~~outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). By June 23, 2017, or the ~~bonds to be called prior to maturity with a make-whole payment as determined by discounting~~expiration date of 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 $57.0tender, $8.1 million of the ~~6.5% Senior Unsecured Notes Due 2016~~outstanding bonds were ~~redeemed at maturity with cash on hand.~~

tendered. 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~~June 26, 2017, 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%accepted all of the ~~initial principal balance quarterly,~~tendered bonds, redeemed and ~~contains covenants and restrictions that are generally consistent with existing~~retired them. On July 7, 2017, DP&L ~~credit agreements.~~notified the Ohio Air Quality Development Authority and the Trustee of the same First Mortgage Bonds that DP&L was going to call at par value (plus accrued and unpaid interest) $21.9 million of these bonds. This call was completed on August 7, 2017. On September 28, 2017, DP&L issued an irrevocable call notice to purchase all of the remaining outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). As of September 30, 2017, all of the bonds were either redeemed or defeased. This was done to facilitate Generation Separation and the release of the DP&L generation assets from the lien of DP&L's First and Refunding Mortgage. The redemption of the $70.0 million principal amount of defeased bonds was completed on October 30, 2017.

~~Debt~~Long-term debt covenants and restrictions

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

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On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending December 31, 2016 and thereafter. With this amendment, DP&L’s Total Debt to Total Capitalization ratio for the period ending September 30, 2017 is 0.46 to 1.00. The amendment also changed, for each agreement, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if DP&L's long-term indebtedness, as required by the PUCO, is less than or equal to $750.0 million. This time period was originally January 1, 2017 to December 31, 2017, but is now the twelve months immediately subsequent to the separation of the generation assets from DP&L.

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

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

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

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

Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage. In July 2017, assets related to the Miami Fort station and the Zimmer station were released from the lien of DP&L's First and Refunding Mortgage in connection with the pending sale. On October 1, 2017, all the other DP&L generation assets transferred to AES Ohio Generation as part of Generation Separation were released from the lien of DP&L’s First and Refunding Mortgage. See Note 13 – Assets and Liabilities Held for Sale for additional information.

Note 78 – Income Taxes

The following table details the effective tax rates for the three and nine months ended September 30, ~~2016~~2017 and ~~2015.~~2016.

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



	Three months ended		Nine months ended
	September 30,		September 30,
	2017	2016	2017	2016
DPL	21.8%	45.7%	36.9%	38.6%

Income tax expense for the nine months ended September 30, ~~2016~~2017 and ~~2015~~2016 was calculated using the estimated annual effective income tax rates for 2017 and 2016 of 36.0% and ~~2015 of~~ 38.6% ~~and 30.8%~~, respectively. ~~For the three and nine months ended September 30, 2016 and 2015, management estimated~~Management estimates the annual effective tax rate based on its forecast of annual pre-tax income. To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the estimated rates ~~estimated~~ could be materially different from the actual effective tax rates.

~~For~~ The effective tax rate for the three months ended September 30, ~~2016,~~ ~~DPL’s~~ ~~current period~~2017 includes the impact of an adjustment relating to flow-through depreciation. The impact of this adjustment decreased the effective tax rate ~~was greater than~~by 10.8% for the ~~estimated annual~~three months ended September 30, 2017. There is no impact on the effective tax rate ~~primarily due to a change in its uncertain tax positions.~~ for the nine months ended September 30, 2017.

The ~~increase~~decrease in the annual effective rate compared to the same period in ~~2015~~2016 is primarily due to athe forecasted ~~pre-tax loss in~~tax expense relating to flow-through depreciation and the ~~2016 tax year.~~projected manufacturer's production deduction.

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Note 89 – 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 each of the nine months ended September 30, ~~2016~~2017 and ~~$5.0 million in employer contributions during the nine months ended September 30, 2015.~~2016.

The amounts presented in the following tables for pension include the collective bargaining plan formula, the traditional management plan formula, the cash balance plan formula and the SERP, in the aggregate. The ~~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~~2017 and ~~2015~~2016 was:


Net Periodic Benefit Cost	Pension
	Three months ended						Nine months ended						Three months ended						Nine months ended
	September 30,						September 30,						September 30,						September 30,
$ in millions	2016			2015			2016			2015			2017			2016			2017			2016
Service cost	$	1.4		$	1.7		$	4.2		$	5.3		$	1.5		$	1.4		$	4.3		$	4.2
Interest cost	3.7			4.4			11.1			13.0			3.5			3.7			10.6			11.1
Expected return on plan assets	(5.7		)	(5.7		)	(17.1		)	(17.0		)	(5.7		)	(5.7		)	(17.1		)	(17.1		)
Plan curtailment ^(a)													—			—			4.1			—
Amortization of unrecognized:
Prior service cost	0.4			0.5			1.4			1.5			0.2			0.4			0.8			1.4
Actuarial loss	1.1			1.5			3.2			4.4			1.3			1.1			4.0			3.2
Net periodic benefit cost	$	0.9		$	2.4		$	2.8		$	7.2		$	0.8		$	0.9		$	6.7		$	2.8


(a)	As a result of the decision to retire certain of DP&L's coal-fired plants, we recognized a plan curtailment of $4.1 million in the first quarter of 2017. See Note 14 – Fixed-asset Impairments for more information.

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
In addition, DP&L provides postretirement health care and life insurance benefits to certain retired employees, their spouses and eligible dependents. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust. These postretirement health care benefits and the related unfunded obligation of $15.6 million at September 30, 2017 and $15.8 million at December 31, 2016 were not material to the financial statements in the periods covered by this report.

Benefit payments, ~~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
Estimated to be paid during					Pension
2017	25.2		1.6		$	6.3
2018	25.8		1.5		$	25.5
2019	26.3		1.4		$	26.0
2020	26.7		1.4		$	26.4
2021 - 2025	134.8		5.7
2021					$	26.7
2022 - 2026					$	139.6

~~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, and all 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~~this subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish ~~these subsidiaries’~~this subsidiary's intended commercial purposes.

At September 30, ~~2016,~~2017, DPL had ~~$16.6~~$38.6 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

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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~~$1.2 million and ~~$0.5~~$2.3 million at September 30, ~~2016~~2017 and December 31, ~~2015,~~2016, respectively.

To date, DPL has not incurred any losses related to the guarantees of AES Ohio Generation’s obligations and we believe it is remote that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees.

Equity Ownership Interest

DP&L ~~owns~~has a 4.9% equity ownership interest in OVEC, which is recorded using the cost method of accounting under GAAP. ~~As of~~At September 30, ~~2016,~~2017, DP&L could be responsible for the repayment of 4.9%, or ~~$74.9~~$71.3 million, of a ~~$1,528.0~~$1,455.5 million debt obligation ~~that has~~comprised of both fixed and variable rate securities with maturities from ~~2018~~2019 to 2040. ~~This would only happen if~~ OVEC could also seek additional contributions from us to avoid a default in the event that other OVEC members defaulted on ~~its debt payments.~~their respective OVEC obligations. As of September 30, ~~2016,~~2017, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations

There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Form 10-K for the fiscal year ended December 31, ~~2015.~~2016.

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under various laws and regulations. We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of September 30, ~~2016,~~2017, cannot be reasonably determined.

Environmental Matters

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

The federal CAA and state laws and regulations (including State Implementation Plans) which require compliance, obtaining permits and reporting as to air emissions;

Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to climate change;


•	Rules and future rules issued by the USEPA, ~~and~~ the Ohio EPA or other authorities that require or will require substantial reductions in SO₂, particulates, mercury, acid gases, NOx, and other air emissions. ~~DP&L~~DPL has installed emission control technology and is taking other measures to comply with required and anticipated reductions;

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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, the Ohio EPA or other authorities associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits; and

Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels consists of fly ash and other coal combustion by-products.

~~Note 11 – 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~~In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.

~~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~~

We have several pending environmental matters associated with ~~its own taxable income and records the provision for income taxes using a separate return method.~~ ~~DPL~~ ~~had net payable balances~~our coal-fired generation units. Some 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~~these matters could have material adverse impacts on the ~~accompanying Balance Sheets on a gross basis.~~operation of the power stations.

Note 1211 – Business Segments

~~At December 31, 2015,~~DPL currently manages the business through two reportable operating segments, the T&D segment and the Generation segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure best reflects the underlying business performance of DPL ~~had two segments consisting~~and is the most relevant measure considered in DPL’s internal evaluation of the ~~operations of two~~financial performance 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.~~segments. The segments are discussed further below:

~~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.~~Transmission and Distribution 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~~T&D segment is comprised primarily of DP&L’s electric ~~generation,~~ transmission and distribution businesses, which ~~generate and deliver~~distribute electricity to residential, commercial, industrial and governmental customers. DP&L ~~generates~~distributes electricity ~~at five coal-fired power plants and~~ ~~DP&L~~ ~~distributes power~~ to ~~approximately 518,000~~more than 520,000 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 electric 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~~regulators. Accordingly, DP&L applies the accounting standards for regulated operations to ~~DPLER~~its electric transmission and distribution businesses recording regulatory assets when incurred costs are expected to be recovered in future customer rates and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were ~~based~~either closed or sold in prior periods. As these assets did not transfer to AES Ohio Generation 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~~October 1, 2017 when DP&L’s generation separation occurred, they are grouped with the ~~sale~~T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment.

Generation Segment

The Generation segment is comprised of ~~DPLER~~AES Ohio Generation and DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. Through September 30, 2017, AES Ohio Generation owned and operated peaking generating facilities, and DP&L owned multiple coal-fired and peaking electric generating facilities. As a result of Generation Separation, the DP&L-owned generating facilities were transferred to AES Ohio Generation on ~~January~~October 1, ~~2016.~~2017. Both AES Ohio Generation and DP&L primarily sell their generated energy and capacity into the PJM wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process.

Included inwithin the “Other” column ~~in the following tables~~ are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs, ~~including~~which include interest expense on DPL’s long-term 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, costs of sales and ~~profits~~expenses are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting segments.

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The following tables present financial information for each of DPL’s reportable business ~~segments:~~segments prior to the October 1, 2017 transfer to AES Ohio Generation:


$ in millions	Utility Segment		Other			Adjustments and Eliminations			DPL Consolidated			T&D		Generation		Other			Adjustments and Eliminations			DPL Consolidated
For the three months ended September 30, 2016

Three months ended September 30, 2017											Three months ended September 30, 2017
Revenues from external customers	$	368.0	$	21.3		$	—		$	389.3		$	184.0	$	137.2	$	2.7		$	—		$	323.9
Intersegment revenues	0.4		2.0			(2.4		)	—			0.2		—		0.9			(1.1		)	—
Total revenues	368.4		23.3			(2.4		)	389.3			$	184.2	$	137.2	$	3.6		$	(1.1	)	$	323.9

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		$	19.6	$	4.7	$	3.0		$	—		$	27.3
Interest expense	$	6.5	$	20.3		$	0.2		$	27.0		$	7.7	$	—	$	19.5		$	—		$	27.2
Income tax expense / (benefit)	$	19.7	$	(7.0	)	$	—		$	12.7
Net income / (loss)	$	30.1	$	(15.0	)	$	—		$	15.1
Income / (loss) from continuing operations before income tax												$	20.0	$	29.9	$	(21.9	)	$	—		$	28.0

Cash capital expenditures	$	26.5	$	4.2		$	—		$	30.7		$	20.6	$	7.9	$	0.7		$	—		$	29.2


$ in millions	Utility Segment		Competitive Retail		Other			Adjustments and Eliminations			DPL Consolidated			T&D		Generation		Other			Adjustments and Eliminations			DPL Consolidated
For the three months ended September 30, 2015

Three months ended September 30, 2016													Three months ended September 30, 2016
Revenues from external customers	$	323.2	$	77.0	$	13.9		$	—		$	414.1		$	215.5	$	170.4	$	3.4		$	—		$	389.3
Intersegment revenues	66.0		—		1.5			(67.5		)	—			0.3		—		2.0			(2.3		)	—
Total revenues	389.2		77.0		15.4			(67.5		)	414.1			$	215.8	$	170.4	$	5.4		$	(2.3	)	$	389.3

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		$	17.8	$	7.7	$	5.4		$	—		$	30.9
Interest expense	$	6.9	$	—	$	22.1		$	(0.1	)	$	28.9		$	6.5	$	0.1	$	20.5		$	(0.1	)	$	27.0
Income tax expense / (benefit)	$	0.8	$	1.6	$	(2.1	)	$	—		$	0.3
Net income / (loss)	$	15.5	$	2.6	$	(9.5	)	$	—		$	8.6
Income / (loss) from continuing operations before income tax														$	36.4	$	14.2	$	(22.8	)	$	—		$	27.8

Cash capital expenditures	$	27.9	$	0.3	$	0.5		$	—		$	28.7		$	19.6	$	10.6	$	0.5		$	—		$	30.7



$ in millions	T&D		Generation			Other			Adjustments and Eliminations			DPL Consolidated
Nine months ended September 30, 2017
Revenues from external customers	$	541.7	$	396.4		$	7.8		$	—		$	945.9
Intersegment revenues	0.8		—			3.6			(4.4		)	—
Total revenues	$	542.5	$	396.4		$	11.4		$	(4.4	)	$	945.9

Depreciation and amortization	$	56.3	$	16.6		$	8.9		$	—		$	81.8
Fixed-asset Impairments (Note 14)	$	—	$	66.3		$	0.1		$	—		$	66.4
Interest expense	$	22.9	$	0.2		$	58.4		$	—		$	81.5
Income / (loss) from continuing operations before income tax	$	60.1	$	(43.7	)	$	(62.8	)	$	—		$	(46.4	)

Cash capital expenditures	$	66.3	$	27.1		$	2.2		$	—		$	95.6

At September 30, 2017
Total assets	$	1,655.3	$	333.0		$	694.4		$	(508.4	)	$	2,174.3

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$ 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			T&D		Generation			Other			Adjustments and Eliminations			DPL Consolidated
For the nine months ended September 30, 2015

Nine months ended September 30, 2016														Nine months ended September 30, 2016
Revenues from external customers	$	957.6	$	274.5		$	49.4		$	—		$	1,281.5		$	604.4	$	470.0		$	7.2		$	—		$	1,081.6
Intersegment revenues	245.0		—			4.4			(249.4		)	—			1.0		—			4.2			(5.2		)	—
Total revenues	1,202.6		274.5			53.8			(249.4		)	1,281.5			$	605.4	$	470.0		$	11.4		$	(5.2	)	$	1,081.6

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		$	55.1	$	44.6		$	0.6		$	—		$	100.3
Fixed-asset Impairments (Note 14)															$	—	$	857.1		$	(621.6	)	$	—		$	235.5
Interest expense	$	24.6	$	0.1		$	65.8		$	(0.2	)	$	90.3		$	17.5	$	0.3		$	61.7		$	(0.2	)	$	79.3
Income tax expense / (benefit)	$	25.0	$	(2.6	)	$	(8.9	)	$	—		$	13.5
Net income / (loss)	$	75.9	$	10.9		$	(27.8	)	$	—		$	59.0
Income / (loss) from continuing operations before income tax															$	97.9	$	(857.2	)	$	564.8		$	—		$	(194.5	)

Cash capital expenditures	$	91.2	$	0.6		$	1.7		$	—		$	93.5		$	61.8	$	46.9		$	1.1		$	—		$	109.8

at December 31, 2015
At December 31, 2016
Total assets	$	3,359.6	$	—		$	1,304.5		$	(1,339.4	)	$	3,324.7		$	1,710.5	$	472.3		$	673.6		$	(437.2	)	$	2,419.2

Note 1312 – 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

~~Table of Contents~~

~~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 atas of 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.~~2016.

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.~~



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

Cash flows related to discontinued operations are included in our Condensed Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(0.7) million ~~and $28.4 million~~ for the nine months ended September 30, ~~2016 and 2015, respectively.~~2016. Cash flows from investing activities for discontinued operations were $75.5 million ~~and $0.7 million~~ for the nine months ended September 30, ~~2016 and 2015, respectively.~~2016. All cash generated from discontinued operations was paid to DPL through dividends for all periods presented.

Note 13 – Assets and Liabilities Held for Sale

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

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following table summarizes the major classes of assets and liabilities classified as held for sale as of September 30, 2017:



$ in millions	September 30, 2017
Assets
Accounts receivable, net ^(a)	$	(11.2	)
Inventories	22.7
Property, plant & equipment, net	44.8
Other prepayments and current assets	0.7
Total assets of the disposal group classified as held for sale in the balance sheet	$	57.0

Liabilities
Accounts payable	$	0.7
Accrued taxes	2.6
Asset retirement obligations	4.4
Other liabilities ^(b)	(0.7		)
Total liabilities of the disposal group classified as held for sale in the balance sheet	$	7.0


(a)	Represents credit balances netted in Accounts Receivable, due to the right of offset with partners


(b)	Represents amounts due to (from) partners for pension benefits associated with partner-operated plants

Zimmer Station and Miami Fort Station's results are reflected within continuing operations in the Condensed Consolidated Statements of Operations. The combined income / (loss) from continuing operations before income tax for Zimmer Station and Miami Fort Station was $11.0 million and $1.4 million for the three months ended September 30, 2017 and 2016, respectively, and $18.9 million and $(9.8) million for the nine months ended September 30, 2017 and 2016, respectively. Zimmer Station and Miami Fort Station are included in the Generation segment.

Note 14 – Fixed-asset ~~Impairment~~Impairments

On March 17, 2017, the Board of Directors of DP&L approved the retirement of the two DP&L operated and co-owned electric generating stations; the Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine (collectively, the “Facilities”) on or before June 1, 2018. The co-owners of these facilities agreed with DP&L to proceed with this plan of retirement. We performed a long-lived asset impairment analysis and determined that the carrying amounts of the Facilities were not recoverable. The asset groups of Stuart Station and Killen Station were determined to have fair values of $3.3 million and $7.9 million, respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $39.1 million and $27.3 million for Stuart Station and Killen Station, respectively.

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

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

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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

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																									THE DAYTON POWER AND LIGHT COMPANY	CONDENSED STATEMENTS OF OPERATIONS
	Three months ended September 30,						Nine months ended September 30,						Three months ended						Nine months ended
													September 30,						September 30,
$ in millions	2016			2015			2016			2015			2017			2016			2017			2016
Revenues	$	368.4		$	389.2		$	1,031.3		$	1,202.6		$	305.6		$	368.4		$	900.8		$	1,031.3

Cost of revenues:
Fuel	71.0			69.0			189.5			188.9
Purchased power	110.0			142.5			328.0			452.3
Net fuel cost													52.8			71.0			152.8			189.5
Net purchased power cost													83.5			110.0			260.7			328.0
Total cost of revenues	181.0			211.5			517.5			641.2			136.3			181.0			413.5			517.5

Gross margin	187.4			177.7			513.8			561.4			169.3			187.4			487.3			513.8

Operating expenses:
Operation and maintenance	85.5			93.5			248.0			261.6			81.7			85.5			245.2			248.0
Depreciation and amortization	24.1			34.6			95.2			103.5			22.7			24.1			68.2			95.2
General taxes	21.2			21.1			62.8			65.0			19.6			21.2			66.8			62.8
Gain on termination of contract	—			—			(27.7		)	—			—			—			—			(27.7		)
Fixed-asset impairment	—			—			857.1			—			—			—			66.3			857.1
Loss / (gain) on asset disposal													(0.3		)	—			15.9			0.2
Other	—			—			0.2			0.4			(4.4		)	—			(4.4		)	—
Total operating expenses	130.8			149.2			1,235.6			430.5			119.3			130.8			458.0			1,235.6

Operating income / (loss)	56.6			28.5			(721.8		)	130.9			50.0			56.6			29.3			(721.8		)

Other income / (expense), net:
Other expense, net
Investment income	0.1			—			0.3			0.2			0.1			0.1			0.2			0.3
Interest expense	(6.5		)	(6.9		)	(17.2		)	(24.6		)	(7.7		)	(6.5		)	(23.1		)	(17.2		)
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		)
Charge for early redemption of debt													(1.0		)	(0.5		)	(1.1		)	(0.5		)
Other expense													(0.2		)	0.1			(1.5		)	(0.2		)
Total other expense, net	(6.8		)	(12.2		)	(17.6		)	(30.0		)	(8.8		)	(6.8		)	(25.5		)	(17.6		)

Earnings / (loss) before income taxes	49.8			16.3			(739.4		)	100.9
Income / (loss) from operations before income tax													41.2			49.8			3.8			(739.4		)

Income tax expense / (benefit)	19.7			0.8			(271.6		)	25.0			11.9			19.7			0.2			(271.6		)

Net income / (loss)	30.1			15.5			(467.8		)	75.9			29.3			30.1			3.6			(467.8		)

Dividends on preferred stock	0.3			0.3			0.7			0.7			—			0.3			—			0.7

Income / (loss) attributable to common stock	$	29.8		$	15.2		$	(468.5	)	$	75.2		$	29.3		$	29.8		$	3.6		$	(468.5	)

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
Three months ended
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.~~

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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



THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
	Three months ended September 30,						Nine months ended September 30,
$ in millions	2017			2016			2017			2016
Net income / (loss)	$	29.3		$	30.1		$	3.6		$	(467.8	)
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax expense of $(0.1), $0.0, $(0.2) and $(0.1) for each respective period	0.1			0.1			0.4			0.2
Reclassification to earnings, net of income tax expense of $0.0, $0.0, $0.0 and $0.0 for each respective period	—			—			(0.1		)	—
Total change in fair value of available-for-sale securities	0.1			0.1			0.3			0.2
Derivative activity:
Change in derivative fair value, net of income tax (expense) / benefit of $(0.8), $5.2, $(6.6) and $(12.2) for each respective period	1.4			9.5			12.1			22.5
Reclassification to earnings, net of income tax benefit of $1.4, $3.0, $3.3 and $13.5 for each respective period	(2.4		)	(5.6		)	(6.0		)	(24.8		)
Total change in fair value of derivatives	(1.0		)	3.9			6.1			(2.3		)
Pension and postretirement activity:
Prior service costs for the period, net of income tax benefit of $0.0, $0.0, $0.6 and $0.0 for each respective period	—			—			(1.1		)	—
Net loss for period, net of income tax benefit of $0.0, $0.0, $0.2 and $0.0 for each respective period	—			—			(0.5		)	—
Reclassification to earnings, net of income tax expense of $(0.4), $(0.4), $(2.1) and $(1.6) for each respective period	0.7			0.7			3.8			1.7
Total change in unfunded pension obligation	0.7			0.7			2.2			1.7

Other comprehensive income / (loss)	(0.2		)	4.7			8.6			(0.4		)

Net comprehensive income / (loss)	$	29.1		$	34.8		$	12.2		$	(468.2	)

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

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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
—



THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS
$ in millions	September 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	15.3		$	1.6
Restricted cash	2.0			29.0
Accounts receivable, net (Note 2)	107.9			134.6
Inventories (Note 2)	26.9			75.8
Taxes applicable to subsequent years	19.2			79.2
Regulatory assets, current	4.5			0.1
Other prepayments and current assets	21.8			32.4
Assets held for sale - current (Note 13)	57.0			—
Total current assets	254.6			352.7

Property, plant & equipment:
Property, plant & equipment	2,345.4			2,398.6
Less: Accumulated depreciation and amortization	(1,060.6		)	(1,047.9		)
	1,284.8			1,350.7
Construction work in process	52.3			89.9
Total net property, plant & equipment	1,337.1			1,440.6

Other non-current assets:
Regulatory assets, non-current	209.4			203.9
Intangible assets, net of amortization	19.9			23.0
Other deferred assets	12.3			14.9
Total other non-current assets	241.6			241.8
Total assets	$	1,833.3		$	2,035.1

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt (Note 7)	$	4.7		$	4.7
Short-term debt (Note 7)	15.0			5.0
Accounts payable	56.6			110.5
Accrued taxes	59.2			75.7
Accrued interest	0.8			2.1
Security deposits	16.4			15.2
Regulatory liabilities, current	20.0			33.7
Other current liabilities	31.0			48.3
Liabilities held for sale - current (Note 13)	6.0			—
Total current liabilities	209.7			295.2

Non-current liabilities:
Long-term debt (Note 7)	643.3			744.7
Deferred taxes	155.1			146.3
Taxes payable	4.8			84.1
Regulatory liabilities, non-current	134.5			130.4
Pension, retiree and other benefits	100.7			101.6
Unamortized investment tax credit	16.1			17.7
Asset retirement obligations	131.0			135.2
Other deferred credits	12.4			17.6
Total non-current liabilities	1,197.9			1,377.6

Commitments and contingencies (Note 11)

Common shareholder's equity:
Common stock, at par value of $0.01 per share	0.4			0.4
250,000,000 shares authorized, 41,172,173 shares issued and outstanding
Other paid-in capital	791.9			810.7
Accumulated other comprehensive loss	(33.9		)	(42.5		)
Accumulated deficit	(332.7		)	(406.3		)
Total common shareholder's equity	425.7			362.3
Total liabilities and shareholder's equity	$	1,833.3		$	2,035.1

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
	Nine months ended September 30,
$ in millions	2017			2016
Cash flows from operating activities:
Net income / (loss)	$	3.6		$	(467.8	)
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Depreciation and amortization	68.2			95.2
Charge for early redemption of debt	1.1			0.5
Deferred income taxes	1.6			(314.2		)
Fixed-asset impairment	66.3			857.1
Loss on asset disposal	15.9			0.2
Changes in certain assets and liabilities:
Accounts receivable	20.5			(11.0		)
Inventories	10.0			29.4
Prepaid taxes	—			2.7
Taxes applicable to subsequent years	60.0			59.9
Deferred regulatory costs, net	(6.5		)	19.5
Accounts payable	(58.4		)	(13.5		)
Accrued taxes payable	(83.9		)	(43.2		)
Accrued interest payable	(1.5		)	(3.3		)
Security deposits	1.1			(0.6		)
Pension, retiree and other benefits	3.8			(2.2		)
Other	(3.1		)	11.7
Net cash provided by operating activities	98.7			220.4
Cash flows from investing activities:
Capital expenditures	(82.4		)	(98.3		)
Purchase of renewable energy credits	(0.1		)	(0.3		)
Decrease in restricted cash	27.0			5.5
Insurance proceeds	12.5			5.6
Other investing activities, net	0.3			0.9
Net cash used in investing activities	(42.7		)	(86.6		)
Cash flows from financing activities:
Dividends and returns of capital paid to parent	(19.0		)	—
Borrowings from revolving credit facilities	30.0			—
Repayment of borrowings from revolving credit facilities	(15.0		)	—
Capital contributions from parent	70.0			—
Issuance of long-term debt, net of discount	—			442.8
Retirement of long-term debt	(103.3		)	(445.3		)
Payments of deferred financing costs	—			(8.0		)
Issuance of short-term debt - related party	30.0			5.0
Repayment of short-term debt - related party	(35.0		)	(40.0		)
Other financing activities, net	—			(0.8		)
Net cash used in financing activities	(42.3		)	(46.3		)
Cash and cash equivalents:
Net change	13.7			87.5
Balance at beginning of period	1.6			5.4
Cash and cash equivalents at end of period	$	15.3		$	92.9
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	22.3		$	16.3
Income taxes paid, net	$	22.2		$	0.3
Non-cash financing and investing activities:
Accruals for capital expenditures	$	7.7		$	10.1
Equity contribution to settle liability	$	—		$	7.5

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

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The Dayton Power and Light Company

Notes to Condensed Financial Statements (Unaudited)

Note 1 – Overview and Summary of Significant Accounting Policies

Description of Business

DP&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~~retail transmission and ~~transmission retail~~distribution services are still regulated. DP&L has the exclusive right to provide such ~~distribution~~transmission and ~~transmission~~distribution services to approximately ~~518,000~~520,000 customers located in West Central Ohio. Additionally, DP&L ~~offers~~procures retail SSO electric service toon behalf of residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. As of September 30, 2017, DP&L ~~owns~~owned undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. As of October 1, 2017, the DP&L-owned generating facilities ~~all~~were transferred to AES Ohio Generation, an affiliate of ~~which are included in~~DP&L and wholly-owned subsidiary of DPL, through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. With the ~~financial statements at amortized cost.~~October 1, 2017 transfer of DP&L's generation assets to a separate DPL subsidiary, DP&L has discontinued its generation business operations. Also, Stuart Station Unit 1 was retired on October 1, 2017. 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, health care, data management, manufacturing and defense. DP&L's distribution sales reflect the general economic conditions, seasonal weather patterns, ~~retail competition in our service territory~~the proliferation of energy efficiency and distributed renewable resources and the market price of electricity. From January 1, 2016 through September 30, 2017, DP&L ~~sells~~sold all of its energy and capacity into the wholesale market. DP&L is a subsidiary of DPL.

Through September 30, 2017, DP&L had two reportable segments: the Transmission and Distribution (T&D) segment and the Generation segment. See Note 12 – Business Segments for more information relating to these reportable segments.

DP&L employed ~~1,163~~1,065 people as of September 30, ~~2016.~~2017. As part of Generation Separation on October 1, 2017, DP&L generation employees became employees of AES Ohio Generation, an affiliate of DP&L and wholly-owned subsidiary of DPL. Approximately ~~62%~~61% of ~~all~~DP&L and AES Ohio Generation employees are under a collective bargaining agreement ~~which expires~~that was set to expire on October 31, 2017. The Company and the union representing these employees have agreed to extend the current agreement through January 31, 2018, while continuing to negotiate a new agreement. We are unable to determine what impact a new agreement may have on our operations.

Financial Statement Presentation

DP&L does not have any subsidiaries. As of September 30, 2017, DP&L ~~has~~had undivided ownership interests in five coal-fired generating facilities, various peaking ~~electric~~ generating facilities and numerous transmission facilities, all of which are included in the financial statements at ~~amortized cost.~~the lower of depreciated historical cost or fair value, if impaired. Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Statements of Operations.

Certain immaterial amounts from prior periods have been reclassified to conform to the current period presentation.

In the current period, we have reclassified the presentation of the December 2016 dividend payment which was originally recorded as a charge to Accumulated deficit and is now presented as a charge to Other paid-in capital. This reclassification was to prospectively correct an immaterial error.

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.~~2016.

Table of Contents

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;~~2017; our results of operations for the three and nine months ended September 30, ~~2016~~2017 and ~~2015~~2016 and our cash flows for the nine months ended September 30, ~~2016~~2017 and ~~2015.~~2016. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including, but not limited to, seasonal weather variations, the timing of outages of EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, ~~2016~~2017 may not be indicative of our results that will be realized for the full year ending December 31, ~~2016.~~2017.

~~Table of Contents~~

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

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~~2016-09, Compensation - ~~Imputation of Interest (Subtopic 835-30)~~Stock Compensation (Topic 718): ~~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~~Improvements 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)~~Employee Share-Based Payment Accounting	The standard simplifies the ~~presentation~~following aspects of ~~debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in~~accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the ~~balance sheet~~statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as ~~a direct deduction from the carrying amount~~either equity or liabilities and classification of ~~that debt liability, consistent with debt discounts.~~employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and ~~measurement guidance for debt issuance costs~~tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are ~~not affected by the standard. Transition method: retrospective.~~recognized was adopted on a modified retrospective basis.	January 1, ~~2016~~2017.	~~Deferred financing costs~~The primary effect 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~~adoption was the ~~related debt liabilities.~~recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. The adoption of this standard did not have a material impact on the financial statements.

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~~2015-02, Consolidation (Topic 810): Amendments to~~
Accounting Standard	Description	Date of Adoption	Effect on 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.~~financial statements upon adoption
New Accounting Standards Issued But Not Yet Effective
~~2016-17, Consolidation~~2017-12, Derivatives and Hedging (Topic ~~810)~~815): ~~Interest Held through Related Parties That Are under Common Control~~Targeted improvements to Accounting for Hedging Activities	The standard updates the hedge accounting model in ASC 815 to expand the ability to hedge risk, reduce complexity and ease certain documentation and assessment requirements. It also eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. Transition method: modified retrospective approach and prospective for presentation and disclosures.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements and if we would early adopt it.
2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities	This standard ~~amends~~shortens the period of amortization of the premium on certain callable debt securities to the earliest call date. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost	This standard changes the presentation of non-service cost expense associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in capitalization.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2017-05, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Topic 610-20)	This standard clarifies the scope and application of ASC 610-20 on the sale, transfer, and derecognition of nonfinancial assets and in substance nonfinancial assets to non-customers, including partial sales. It also clarifies that the derecognition of businesses is under scope of ASC 810. Transition method: full or modified retrospective we are in the process of identifying contracts that would not be completed as of January 1, 2018. Based on the assessment of contracts already executed as of the balance sheet date, the contracts that may require any type of assessment under the new standard are limited.	January 1, 2018.	We will adopt the standard on January 1, 2018; see below for the evaluation of ~~whether a reporting entity is~~ the ~~primary beneficiary~~impact of its adoption on the financial statements. We will adopt the standard on January 1, 2018 and plan to use the modified retrospective approach.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a ~~VIE by amending how~~Business	This standard provides guidance to assist the entities with evaluating when a ~~reporting entity, that~~set of transferred assets and activities is a ~~single decision maker of a VIE, treats indirect interests in that entity held through related parties that are under common control.~~ business. Transition method: ~~retrospectively.~~prospective.	January 1, ~~2017~~ 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)	This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity ~~recognizes~~recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified ~~retrospective method.~~retrospective.	January 1, ~~2018~~ 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~~ 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~~2016-02, Leases (Topic ~~718): Improvements~~842)	This standard requires lessees to ~~Employee Share-Based Payment Accounting~~	~~The standard simplifies~~recognize assets and liabilities for most leases but recognize expenses in a manner similar to today’s accounting. For lessors, the ~~following aspects of~~guidance modifies the lease classification criteria and the accounting for ~~share-based payment awards: accounting for income taxes, classification~~sales-type and direct financing leases. The guidance also eliminates today’s real estate-specific provisions. Transition method: modified retrospective at the beginning of ~~excess tax benefits~~the earliest comparative period presented in the financial statements (January 1, 2017). We have established a task force focused on the ~~statement~~identification of ~~cash flows, forfeitures, statutory tax withholding requirements, classification~~contracts that would be under the scope of ~~awards as either equity or liabilities~~the new standard and ~~classification~~on the assessment and measurement of ~~employee taxes paid on statement~~the right-of-use asset and related liability. The implementation team is in the process of ~~cash flows when an employer withholds shares for tax-withholding purposes. Transition method: Various.~~evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard.	January 1, ~~2017.~~ 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements. We intend to adopt the standard as of January 1, 2019.
~~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 606,2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05, 2017-13 Revenue from Contracts with ~~Customers. Transition method: modified retrospective approach with certain practical expedients.~~Customers (Topic 606)	~~January 1, 2019. Early adoption is permitted.~~	~~We are currently evaluating~~See discussion of 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.ASUs below.	January 1, 2018. ~~Limited early adoption permitted.~~	We ~~are currently evaluating~~will adopt the standard on January 1, 2018; see below for the evaluation of the impact of ~~adopting~~its adoption on 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.

46In 2016, we established a cross-functional implementation team and are in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.

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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 amendmentsretrospective approach. However, we will continue to assess this conclusion which is dependent on the final impact 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~~2017 and December 31, ~~2015:~~2016:

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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	September 30,			December 31,
$ in millions	2017			2016
Accounts receivable, net:
Unbilled revenue	$	14.4		$	43.0
Customer receivables	68.7			71.2
Amounts due from affiliates	2.3			2.9
Amounts due from partners in jointly-owned plants	17.8			12.7
Other	5.8			6.0
Provision for uncollectible accounts	(1.1		)	(1.2		)
Total accounts receivable, net	$	107.9		$	134.6

Inventories, at average cost:
Fuel and limestone	$	16.8		$	38.8
Plant materials and supplies	9.1			35.3
Other	1.0			1.7
Total inventories, at average cost	$	26.9		$	75.8

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~~2017 and ~~2015~~2016 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							Affected line item in the Condensed Consolidated Statements of Operations	Three months ended						Nine months ended
			September 30,						September 30,								September 30,						September 30,
$ in millions			2016			2015			2016			2015					2017			2016			2017			2016
Gains and losses on cash flow hedges (Note 5):
Gains and losses on Available-for-sale securities activity (Note 5):															Gains and losses on Available-for-sale securities activity (Note 5):
																Other income	$	—		$	—		$	(0.1	)	$	—

Gains and losses on cash flow hedges (Note 6):															Gains and losses on cash flow hedges (Note 6):
		Interest expense	$	(0.3	)	$	(0.3	)	$	(0.9	)	$	(0.9	)		Interest expense	(0.3		)	(0.3		)	(0.8		)	(0.9		)
		Revenue	(9.3		)	(3.8		)	(46.5		)	(7.0		)		Revenue	(4.2		)	(9.3		)	(12.5		)	(46.5		)
		Purchased power	1.0			0.9			9.1			2.7				Purchased power	0.7			1.0			4.0			9.1
		Total before income taxes	(8.6		)	(3.2		)	(38.3		)	(5.2		)		Total before income taxes	(3.8		)	(8.6		)	(9.3		)	(38.3		)
		Tax expense	3.0			1.2			13.5			1.9				Tax expense	1.4			3.0			3.3			13.5
		Net of income taxes	(5.6		)	(2.0		)	(24.8		)	(3.3		)		Net of income taxes	(2.4		)	(5.6		)	(6.0		)	(24.8		)
Amortization of defined benefit pension items (Note 8):

Amortization of defined benefit pension items (Note 9):															Amortization of defined benefit pension items (Note 9):
		Operation and maintenance	1.1			1.4			3.3			4.2				Operation and maintenance	1.1			1.1			5.9			3.3
		Tax benefit	(0.4		)	(0.6		)	(1.6		)	(1.6		)		Tax benefit	(0.4		)	(0.4		)	(2.1		)	(1.6		)
		Net of income taxes	0.7			0.8			1.7			2.6				Net of income taxes	0.7			0.7			3.8			1.7

Total reclassifications for the period, net of income taxes	Total reclassifications for the period, net of income taxes		$	(4.9	)	$	(1.2	)	$	(23.1	)	$	(0.7	)	Total reclassifications for the period, net of income taxes		$	(1.7	)	$	(4.9	)	$	(2.3	)	$	(23.1	)

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The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months ended September 30, ~~2016~~2017 are as follows:

$ in millions Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total
Balance January 1, 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 )



$ in millions	Gains / (losses) on available-for-sale securities			Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total
Balance at January 1, 2017	$	0.7		$	(2.7	)	$	(40.5	)	$	(42.5	)

Other comprehensive income / (loss) before reclassifications	0.4			12.1			(1.6		)	10.9
Amounts reclassified from accumulated other comprehensive income / (loss)	(0.1		)	(6.0		)	3.8			(2.3		)
Net current period other comprehensive income	0.3			6.1			2.2			8.6

Balance at September 30, 2017	$	1.0		$	3.4		$	(38.3	)	$	(33.9	)

Note 3 – Regulatory Matters

Bypassable standard offer energy rates for ~~SSO service. Although it~~ DP&L’s customers based on competitive bid auctions;

Restrictions on DPL making dividend or tax sharing payments; and

Various other riders and competitive retail market enhancements.

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Those appeals are pending, and the outcome and potential financial impact of those appeals cannot be determined at this time. In July 2017, the Office of the Ohio Consumers Counsel filed a motion with the Ohio Supreme Court seeking to stay collection of the reinstated prior rates while the appeals are pending. That stay was denied by the Ohio Supreme Court in September 2017.

~~On August 26, 2016,~~DP&L is subject to a SEET threshold and is required to apply general rules for calculating earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings during a given calendar year. The ESP 3 maintains DP&L’s return on equity SEET threshold at 12% and provides that DMR amounts are excluded from the SEET calculation. A stipulation was reached with 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~~staff agreeing that DP&L ~~to legally separate its generation assets~~did not exceed the SEET threshold for 2015, which was approved 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 effectiveon 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.

6, 2017. On ~~February 22, 2016,~~May 15, 2017, DP&L filed ~~ESP 3 at~~its application to demonstrate that it did not have significantly excessive earnings for calendar year 2016. That case is still pending. In future years, 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~~SEET could have 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~~material effect 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.~~flows.

Note 4 – Property, Plant and Equipment

Coal-fired facilities

As of September 30, 2017, DP&L and certain other Ohio utilities had undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. DP&L’s share of the operations of such facilities is included within the corresponding line in the Condensed Statements of Operations, and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Balance Sheets, except for amounts related to Miami Fort and Zimmer, which are classified as Held for Sale, as described below. Each co-owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.

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



	DP&L Share		DP&L Carrying Value
	Ownership (%)	Summer Production Capacity (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)
Jointly-owned production units
Conesville - Unit 4	16.5	129	$	0.5	$	0.5	$	2.3
Killen - Unit 2	67.0	402	8.5		4.1		—
Miami Fort - Units 7 and 8 (a)	36.0	368	31.3		3.3		5.1
Stuart - Units 2 through 4	35.0	606	0.7		0.7		—
Zimmer - Unit 1 (a)	28.1	371	21.3		15.3		5.2
Transmission (at varying percentages)			98.6		66.9		—
Total		1,876	$	160.9	$	90.8	$	12.6


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

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

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AROs

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

Changes in the Liability for Generation AROs



$ in millions
Balance at January 1, 2017	$	135.2
Additions	0.1
Revisions to cash flow and timing estimates	(4.8		)
Accretion expense	4.0
Settlements	(0.1		)
Reclassified to Liabilities held for sale	(3.4		)
Balance at September 30, 2017	$	131.0

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

Note 5 – Fair Value

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	September 30, 2016				December 31, 2015				September 30, 2017				December 31, 2016
$ in millions	Cost		Fair Value		Cost		Fair Value		Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.3	$	0.3	$	0.2	$	0.2	$	0.4	$	0.4	$	0.4	$	0.4
Equity securities	2.4		3.4		3.0		3.8		2.6		4.1		2.4		3.4
Debt securities	4.5		4.5		4.4		4.3		4.2		4.3		4.4		4.4
Hedge funds	0.2		0.2		0.4		0.4		0.1		0.1		—		0.1
Real estate	0.3		0.3		0.3		0.3		—		—		0.3		0.3
Tangible assets									0.1		0.1		0.1		0.1
Total assets	$	7.7	$	8.7	$	8.3	$	9.0	$	7.4	$	9.0	$	7.6	$	8.7

	Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Debt	$	748.5	$	763.5	$	756.7	$	764.2
Long-term debt (a)									$	647.7	$	659.5	$	749.0	$	763.5


(a)	Amounts exclude immaterial capital lease obligations

These financial instruments are not subject to master netting agreements or collateral requirements and as such are presented in the Condensed Balance Sheet at their gross fair value, except for ~~Debt,~~Long-term debt, which is presented at amortized carrying value.

~~Debt~~Fair Value Hierarchy

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 ~~recognized~~active); or

Level 3 (unobservable inputs) reflecting management’s own assumptions about the inputs used in pricing the ~~financial statements as debt is presented at cost, net~~asset or liability).

Valuations of ~~unamortized premium or discount~~assets and ~~deferred financing costs~~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 ~~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.~~our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.

~~Table~~We did not have any transfers of ~~Contents~~

the fair values of our financial instruments between Level 1, Level 2 or Level 3 of the fair value hierarchy during the nine months ended September 30, 2017 or 2016.

Master Trust Assets

DP&L had $1.5 million ($1.0 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2017 and $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.~~2016.

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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~~Long-term debt

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

~~Level 3 (unobservable inputs).~~

~~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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maturities that range from 2020 to 2061.

The fair value of assets and liabilities at September 30, ~~2016~~2017 and December 31, ~~2015~~2016 and the respective category within the fair value hierarchy for DP&L was determined as follows:

																	Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3				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		Fair value at September 30, 2017 (a)		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	—	$	—	$	0.4	$	0.4	$	—	$	—
Equity securities	3.4		—		3.4		—		4.1		—		4.1		—
Debt securities	4.5		—		4.5		—		4.3		—		4.3		—
Hedge funds	0.2		—		0.2		—		0.1		—		0.1		—
Real estate	0.3		—		0.3		—
Tangible assets									0.1		—		0.1		—
Total Master Trust assets	8.7		0.3		8.4		—		9.0		0.4		8.6		—

Derivative assets
FTRs	0.1		—		—		0.1
Natural gas futures									0.9		0.9		—		—
Interest rate hedges									—		—		—		—
Forward power contracts	33.2		—		32.6		0.6		10.8		—		10.8		—
Total derivative assets	33.3		—		32.6		0.7		11.7		0.9		10.8		—

Total assets	$	42.0	$	0.3	$	41.0	$	0.7	$	20.7	$	1.3	$	19.4	$	—

Liabilities
Derivative liabilities
FTRs									$	0.5	$	—	$	—	$	0.5
Interest rate hedges									—		—		—		—
Natural gas futures									0.8		0.8		—		—
Forward power contracts	$	31.0	$	—	$	26.0	$	5.0	8.1		—		8.1		—
Total derivative liabilities	31.0		—		26.0		5.0		9.4		0.8		8.1		0.5

Debt	763.5		—		745.5		18.0
Long-term debt (b)									659.5		—		641.6		17.9

Total liabilities	$	794.5	$	—	$	771.5	$	23.0	$	668.9	$	0.8	$	649.7	$	18.4


(a)	Includes credit valuation adjustment


(b)	Amounts exclude immaterial capital lease obligations

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																		Assets and Liabilities at Fair Value
			Level 1		Level 2			Level 3				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		Fair value at December 31, 2016 (a)		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.2	$	0.2	$	—		$	—	$	0.4	$	0.4	$	—	$	—
Equity securities	3.8		—		3.8			—		3.4		—		3.4		—
Debt securities	4.3		—		4.3			—		4.4		—		4.4		—
Hedge funds	0.4		—		0.4			—		0.1		—		0.1		—
Real estate	0.3		—		0.3			—		0.3		—		0.3		—
Tangible assets										0.1		—		0.1		—
Total Master Trust assets	9.0		0.2		8.8			—		8.7		0.4		8.3		—

Derivative assets
FTRs	0.2		—		—			0.2		0.1		—		—		0.1
Interest rate hedges										1.2		—		1.2		—
Forward power contracts	30.6		—		30.6			—		19.5		—		19.5		—
Total Derivative assets	30.8		—		30.6			0.2		20.8		—		20.7		0.1

Total assets	$	39.8	$	0.2	$	39.4		$	0.2	$	29.5	$	0.4	$	29.0	$	0.1

Liabilities
Derivative liabilities
FTRs	$	0.5	$	—	$	—		$	0.5
Interest rate hedges										$	0.7	$	—	$	0.7	$	—
Forward power contracts	27.0		—		23.9			3.1		28.5		—		26.0		2.5
Total Derivative liabilities	27.5		—		23.9			3.6		29.2		—		26.7		2.5
							��
Debt	764.2		—		746.1			18.1
Long-term debt (b)										763.5		—		745.5		18.0

Total liabilities	$	791.7	$	—	$	770.0		$	21.7	$	792.7	$	—	$	772.2	$	20.5


(a)	Includes credit valuation adjustment


(b)	Amounts exclude immaterial capital lease obligations

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

Approximately 86% of the inputs to the fair value of our derivative instruments are from quoted market prices.

~~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. As a result of changes in our estimates of costs to be incurred for our AROs, we decreased our AROs by $4.8 million in the first nine months of 2017. AROs for ash ponds, asbestos, ash landfills, river structures and underground storage tanks decreased by a net amount of $0.8 million and 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, 2017 and 2016, respectively. In addition, there was a $3.4 million decrease in the ARO liability during the nine months ended September 30, 2017 related to AROs at Miami Fort and Zimmer being reclassified to Liabilities held for sale - current.

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 the Stuart, Killen and Zimmer EGUs. As a result, we performed a long-lived asset impairment analysis during the second quarter of 2016 and ~~2015, respectively.~~determined that the carrying amount of these assets were not recoverable. See Note 14 – Fixed-asset Impairments.

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



	Carrying		Fair Value						Gross
	Amount ^(b)		Level 1		Level 2		Level 3		Loss
$ in millions	Nine months ended September 30, 2017
Assets
Long-lived assets ^(a)
Stuart	$	42.3	$	—	$	—	$	3.3	$	39.0
Killen	$	35.2	$	—	$	—	$	7.9	$	27.3
									$	66.3

	Nine months ended September 30, 2016
Assets
Long-lived assets ^(a)
Stuart	$	456.4	$	—	$	—	$	164.4	$	292.0
Killen	$	330.5	$	—	$	—	$	84.3	$	246.2
Zimmer	$	429.9	$	—	$	—	$	111.0	$	318.9
									$	857.1

(a)See Note 1214 – Fixed-asset ~~Impairment~~Impairments for further information

(b)Carrying amount at date of valuation

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The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the nine months ended September 30, 2017:



$ in millions	Fair value		Valuation technique	Unobservable input	Weighted average
Long-lived assets held and used:
Stuart	$	3.3	Discounted cash flow	Pre-tax operating margin (through remaining life)	10.0	%
				Weighted-average cost of capital	7.0	%

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

The 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%



$ in millions	Fair value		Valuation technique	Unobservable input	Weighted average
Long-lived assets held and used:
Stuart	$	164.4	Discounted cash flow	Annual revenue growth	-9.0% to 10.0% (2.0%)
				Annual pre-tax operating margin	-29.0% to 52.0% (5.0%)
				Weighted-average cost of capital	9.0%

Killen	$	84.3	Discounted cash flow	Annual revenue growth	-11.0% to 13.0% (2.0%)
				Annual pre-tax operating margin	-50.0% to 67.0% (6.0%)
				Weighted-average cost of capital	11.0%

Zimmer	$	111.0	Discounted cash flow	Annual revenue growth	-14.0% to 13.0% (1.0%)
				Annual pre-tax operating margin	-46.0% to 80.0% (4.0%)
				Weighted-average cost of capital	9.0%

Note 56 – Derivative Instruments and Hedging Activities

In the normal course of business, DP&L enters into various financial ~~arrangements,~~instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for ~~commodities.~~commodities and interest rate risk associated with our long-term debt. The

~~Table of Contents~~

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.~~if they qualify under FASC 815 for accounting purposes.

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At September 30, ~~2016,~~2017, DP&L&L's ~~had the following outstanding~~ derivative ~~instruments:~~instruments were as follows:


Commodity	Accounting Treatment ^(a)	Unit	Purchases (in thousands)	Sales (in thousands)		Net Purchases/ (Sales) (in thousands)		Accounting Treatment ^(a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	2.8	—		2.8		Not designated	MWh	3.4		—			3.4
Natural gas futures	Not designated	Dths	—	(20.0	)	(20.0	)	Not designated	Dths	6,625.0		(390.0		)	6,235.0
Forward power contracts	Designated	MWh	607.6	(10,699.9	)	(10,092.3	)	Designated	MWh	649.0		(2,478.9		)	(1,829.9		)
Forward power contracts	Not designated	MWh	2,866.9	(2,419.8	)	447.1		Not designated	MWh	1,082.8		(1,060.0		)	22.8
Interest rate swaps								Designated	USD	$	200,000.0	$	—		$	200,000.0

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

At December 31, ~~2015,~~2016, DP&L&L's ~~had the following outstanding~~ derivative ~~instruments:~~instruments were as follows:


Commodity	Accounting Treatment ^(a)	Unit	Purchases (in thousands)	Sales (in thousands)		Net Purchases/ (Sales) (in thousands)		Accounting Treatment ^(a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	10.2	—		10.2		Not designated	MWh	2.3		—			2.3
Natural gas futures								Not designated	Dths	1,590.0		—			1,590.0
Forward power contracts	Designated	MWh	1,676.7	(7,795.8	)	(6,119.1	)	Designated	MWh	342.9		(9,974.5		)	(9,631.6		)
Forward power contracts	Not designated	MWh	5,049.9	(1,665.7	)	3,384.2		Not designated	MWh	2,568.3		(2,037.5		)	530.8
Interest rate swaps								Designated	USD	$	200,000.0	$	—		$	200,000.0

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

Cash Flow Hedges

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The following ~~table provides~~tables provide information ~~for~~ ~~DP&L~~ concerning gains or losses recognized in AOCI for the cash flow hedges for the three and nine months ended September 30, ~~2016~~2017 and ~~2015:~~2016:


	Three months ended						Three months ended						Three months ended						Three months ended
	September 30, 2016						September 30, 2015						September 30, 2017						September 30, 2016
				Interest						Interest						Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge			Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	3.4		$	1.6		$	1.1		$	2.2		$	3.0		$	1.4		$	3.4		$	1.6
Net gains associated with current period hedging transactions	9.5			—			7.8			—			1.3			0.1			9.5			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.2		)	—			(0.1		)	—			(0.2		)	—			(0.2		)
Revenues	(6.0		)	—			(2.5		)	—			(2.7		)	—			(6.0		)	—
Purchased power	0.6			—			0.6			—			0.5			—			0.6			—
Ending accumulated derivative gains in AOCI	$	7.5		$	1.4		$	7.0		$	2.1		$	2.1		$	1.3		$	7.5		$	1.4

	Nine months ended						Nine months ended						Nine months ended						Nine months ended
	September 30, 2016						September 30, 2015						September 30, 2017						September 30, 2016
				Interest						Interest						Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge			Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	9.2		$	2.0		$	0.2		$	2.6
Beginning accumulated derivative gains / (losses) in AOCI													$	(4.3	)	$	1.6		$	9.2		$	2.0
Net gains associated with current period hedging transactions	22.5			—			9.6			—			11.9			0.2			22.5			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.6		)	—			(0.5		)	—			(0.5		)	—			(0.6		)
Revenues	(30.1		)	—			(4.5		)	—			(8.1		)	—			(30.1		)	—
Purchased power	5.9			—			1.7			—			2.6			—			5.9			—
Ending accumulated derivative gains in AOCI	$	7.5		$	1.4		$	7.0		$	2.1		$	2.1		$	1.3		$	7.5		$	1.4

Portion expected to be reclassified to earnings in the next twelve months ^(a)	$	—		$	(0.7	)							$	1.5		$	(0.4	)

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	15			0									6			37


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

Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented.

Derivatives not designated as hedges

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchase and normal sales scope exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the Condensed 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 futures, and certain forward power contracts are currently marked to market.

~~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~~DP&L's derivatives not designated as hedging instruments for the three and nine months ended September 30, ~~2016~~2017 and ~~2015:~~2016:

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 )

~~Table of Contents~~


For the nine months ended September 30, 2015
For the three months ended September 30, 2017																	For the three months ended September 30, 2017
$ in millions		Heating Oil			FTRs			Power			Natural Gas			Total				FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)		$	0.4		$	0.2		$	(5.0	)	0.1			$	(4.3	)		$	0.2		$	(1.4	)	$	—		$	(1.2	)
Realized loss		(0.3		)	(0.1		)	(8.1		)	(0.1		)	(8.6		)
Realized gain / (loss)																		0.2			1.9			(0.2		)	1.9
Total		$	0.1		$	0.1		$	(13.1	)	$	—		$	(12.9	)		$	0.4		$	0.5		$	(0.2	)	$	0.7
Recorded in Balance Sheet:
Regulatory asset		$	0.1		$	—		$	—		$	—		$	0.1

Recorded in Income Statement: gain / (loss)	Recorded in Income Statement: gain / (loss)
Revenues																		$	—		$	3.3		$	—		$	3.3
Purchased power		—			0.1			(21.9		)	—			(21.8		)		0.4			(2.8		)	(0.2		)	(2.6		)
Fuel		—			—			8.8			—			8.8
Total		$	0.1		$	0.1		$	(13.1	)	$	—		$	(12.9	)		$	0.4		$	0.5		$	(0.2	)	$	0.7

For the three months ended September 30, 2016																	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 nine months ended September 30, 2017																	For the nine months ended September 30, 2017
$ in millions																		FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)																		$	(0.5	)	$	2.2		$	(0.8	)	$	0.9
Realized gain / (loss)																		0.5			(1.5		)	(0.3		)	(1.3		)
Total																		$	—		$	0.7		$	(1.1	)	$	(0.4	)

Recorded in Income Statement: gain / (loss)
Revenues																		$	—		$	(2.7	)	$	—		$	(2.7	)
Purchased power																		—			3.4			(1.1		)	2.3
Total																		$	—		$	0.7		$	(1.1	)	$	(0.4	)

For the nine months ended September 30, 2016																	For the nine months ended September 30, 2016
$ in millions																		FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)																		$	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	)

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

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

																								Fair Values of Derivative Instruments
at September 30, 2016
at September 30, 2017												at September 30, 2017
				Gross Amounts Not Offset in the Condensed Balance Sheets												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			Hedging Designation	Gross Fair Value as presented in the Balance Sheets ^(a)		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	15.6	$	(13.3	)	$	—		$	2.3		Designated	$	7.0	$	(4.6	)	$	—		$	2.4
Forward power contracts	Not designated	8.8		(7.7		)	—			1.1			Not designated	3.5		(2.7		)	—			0.8
FTRs	Not designated	0.1		—			—			0.1
Natural gas futures													Not designated	—		—			—			—

Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	7.4		(1.1		)	—			6.3
Interest rate swap													Designated	0.9		—			—			0.9
Natural gas futures													Not designated	—		—			—			—
Forward power contracts	Not designated	1.4		(0.7		)	—			0.7			Not designated	0.3		—			—			0.3
Total assets		$	33.3	$	(22.8	)	$	—		$	10.5			$	11.7	$	(7.3	)	$	—		$	4.4

Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	16.1	$	(13.3	)	$	(2.7	)	$	0.1		Designated	$	4.6	$	(4.6	)	$	—		$	—
Interest rate swaps													Designated	—		—			—			—
Forward power contracts	Not designated	12.9		(7.7		)	(2.4		)	2.8			Not designated	3.5		(2.7		)	(0.7		)	0.1
Natural gas futures													Not designated	0.8		—			(0.8		)	—
FTRs													Not designated	0.5		—			—			0.5

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
Natural gas futures													Not designated	—		—			—			—
Total liabilities		$	31.0	$	(22.8	)	$	(5.1	)	$	3.1			$	9.4	$	(7.3	)	$	(1.5	)	$	0.6

(a) includes credit valuation adjustment

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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
at December 31, 2016												at December 31, 2016
				Gross Amounts Not Offset in the Condensed Balance Sheets												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			Hedging Designation	Gross Fair Value as presented in the Balance Sheets ^(a)		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	16.2	$	(7.1	)	$	—		$	9.1		Designated	$	11.0	$	(10.5	)	$	—		$	0.5
Forward power contracts	Not designated	7.4		(5.5		)	—			1.9			Not designated	6.0		(4.7		)	—			1.3
FTRs	Not designated	0.2		(0.2		)	—			—			Not designated	0.1		—			—			0.1

Long-term derivative positions (presented in Other deferred assets)
Interest rate swaps													Designated	1.2		—			—			1.2
Forward power contracts	Designated	3.0		(2.4		)	—			0.6			Designated	0.6		(0.6		)	—			—
Forward power contracts	Not designated	4.0		(2.7		)	—			1.3			Not designated	1.9		(1.0		)	—			0.9
Total assets		$	30.8	$	(17.9	)	$	—		$	12.9			$	20.8	$	(16.8	)	$	—		$	4.0

Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	7.1	$	(7.1	)	$	—		$	—		Designated	$	16.4	$	(10.5	)	$	(5.5	)	$	0.4
Interest rate swaps													Designated	0.7		—			—			0.7
Forward power contracts	Not designated	14.5		(5.5		)	(8.0		)	1.0			Not designated	7.7		(4.7		)	—			3.0
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			Designated	2.4		(0.6		)	(0.8		)	1.0
Forward power contracts	Not designated	2.7		(2.7		)	—			—			Not designated	2.0		(1.0		)	—			1.0
Total liabilities		$	27.5	$	(17.9	)	$	(8.0	)	$	1.6			$	29.2	$	(16.8	)	$	(6.3	)	$	6.1

(a) includes credit valuation adjustment

Credit risk-related contingent features

The aggregate fair value of DP&L’s commodity derivative instruments that were in a MTM loss position at September 30, ~~2016~~2017 was ~~$31.0~~$9.4 million. ~~$22.8~~$1.5 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~~$7.3 million. ~~Since our~~If DP&L's long-term debt iswere to fall below investment grade, weDP&L could ~~have~~be required to post collateral for the remaining ~~$3.1~~$0.6 million.

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Note 67 – Long-term Debt

The following table ~~provides a summary of~~summarizes DP&L's outstanding 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



	Interest		September 30,			December 31,
$ in millions	Rate	Maturity	2017			2016
Term loan - rates from 4.01% - 4.49% (a) and 4.00% - 4.01% (b)		2022	$	441.7		$	445.0
Tax-exempt First Mortgage Bonds	4.8%	2036	—			100.0
Tax-exempt First Mortgage Bonds - rates from 1.52% - 1.83% (a) and 1.29% - 1.42% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	17.9			18.0
Capital leases			0.3			0.4
Unamortized deferred financing costs			(9.9		)	(11.8		)
Unamortized long-term debt discounts			(2.0		)	(2.2		)
Total long-term debt			648.0			749.4
Less: current portion			(4.7		)	(4.7		)
Long-term debt, net of current portion			$	643.3		$	744.7

(a)Range of interest rates for the nine months ended September 30, ~~2016.~~2017.

(b)Range of interest rates for the year ended December 31, ~~2015.~~2016.

Deferred financing costs are amortized over the remaining life of the debt using the effective interest method. Premiums or discounts on long-term debt are amortized over the remaining life of the debt using the effective interest method.

Line of credit

At September 30, 2017, DP&L had $15.0 million in outstanding borrowings on its line of credit.

Significant transactions

On ~~August 24, 2016,~~May 26, 2017, DP&L~~refinanced its 1.875%~~ commenced a tender offer to purchase any and all of the outstanding 4.8% tax-exempt First Mortgage Bonds ~~Due 2016, with a variable rate Term Loan B~~at par value (plus accrued and unpaid interest). By June 23, 2017, or the expiration date of ~~$445.0~~the tender, $8.1 million ~~maturing on August 24, 2022 and secured by a pledge~~ of the outstanding bonds were tendered. On June 26, 2017, 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%accepted all of the ~~initial principal balance quarterly,~~tendered bonds, redeemed and ~~contains covenants and restrictions that are generally consistent with existing~~retired them. On July 7, 2017, DP&L ~~credit agreements.~~notified the Ohio Air Quality Development Authority and the Trustee of the same First Mortgage Bonds that DP&L was going to call at par value (plus accrued and unpaid interest) $21.9 million of these bonds. This call was completed on August 7, 2017. On September 28, 2017, DP&L issued an irrevocable call notice to purchase all of the remaining outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). As of September 30, 2017, all of the bonds were either redeemed or defeased. This was done to facilitate Generation Separation and the release of the DP&L generation assets from the lien of DP&L's First and Refunding Mortgage. The redemption of the $70.0 million principal amount of defeased bonds was completed on October 30, 2017.

~~Debt~~Long-term debt covenants and restrictions

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

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

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

Note 78 – Income Taxes

The following table details the effective tax rates for the three and nine months ended September 30, ~~2016~~2017 and ~~2015.~~2016.

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



	Three months ended		Nine months ended
	September 30,		September 30,
	2017	2016	2017	2016
DP&L	28.9%	39.6%	5.3%	36.7%

Income tax expense for the ~~three and~~ nine months ended September 30, ~~2016~~2017 and ~~2015~~2016 was calculated using the estimated annual effective income tax rates for 2017 and 2016 of 19.0% and ~~2015 of~~ 36.7% ~~and 29.0%~~, respectively. ~~For the three and nine months ended September 30, 2016 and 2015 management estimated~~Management estimates the annual effective tax rate based on its forecast of annual pre-tax income. To the extent that actual pre-tax results for the year differ from the forecasts

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

~~For~~ The effective tax rate for the three months ended September 30, ~~2016,~~ ~~DP&L’s~~ ~~current period~~2017 includes the impact of an adjustment relating to flow-through depreciation. The impact of this adjustment increased the effective tax rate ~~was greater than the estimated annual effective rate primarily due to a change in its uncertain tax positions and the deduction~~by 8.2% for the ~~preferred stock dividends.~~ three months ended September 30, 2017. There is no impact on the effective tax rate for the nine months ended September 30, 2017.

Income taxes paid, net, were $22.2 million and $0.3 million for the nine months ended September 30, 2017 and 2016, ~~tax year.~~respectively. For the nine months ended September 30, 2017, the $22.2 million represented payments made to DPL.

Note 89 – Benefit Plans

DP&L sponsors a defined benefit pension plan for the vast majority of its employees.

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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~~2017 and ~~2015~~2016 was:


Net Periodic Benefit Cost	Pension
	Three months ended						Nine months ended						Three months ended						Nine months ended
	September 30,						September 30,						September 30,						September 30,
$ in millions	2016			2015			2016			2015			2017			2016			2017			2016
Service cost	$	1.4		$	1.8		$	4.2		$	5.3		$	1.5		$	1.4		$	4.3		$	4.2
Interest cost	3.7			4.2			11.1			12.8			3.5			3.7			10.6			11.1
Expected return on plan assets	(5.7		)	(5.6		)	(17.1		)	(16.8		)	(5.7		)	(5.7		)	(17.1		)	(17.1		)
Plan curtailment ^(a)													—			—			5.6			—
Amortization of unrecognized:
Prior service cost	0.8			0.9			2.3			2.5			0.3			0.8			1.1			2.3
Actuarial loss	1.8			2.4			5.4			7.2			2.1			1.8			6.6			5.4
Net periodic benefit cost	$	2.0		$	3.7		$	5.9		$	11.0		$	1.7		$	2.0		$	11.1		$	5.9


(a)	As a result of the decision to retire certain of DP&L's coal-fired plants, we recognized a plan curtailment of $5.6 million in the first quarter of 2017. See Note 14 – Fixed-asset Impairments for more information.

~~Table~~In addition, DP&L provides postretirement health care and life insurance benefits to certain retired employees, their spouses and eligible dependents. We have funded a portion of ~~Contents~~

the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust. These postretirement health care benefits and the related unfunded obligation of $15.6 million at September 30, 2017 and $15.8 million at December 31, 2016 were not material to the financial statements in the periods covered by this report.

Benefit payments, ~~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
Estimated to be paid during					Pension
2017	25.2		1.6		$	6.3
2018	25.8		1.5		$	25.5
2019	26.3		1.4		$	26.0
2020	26.7		1.4		$	26.4
2021 - 2025	134.8		5.7
2021					$	26.7
2022 - 2026					$	139.6

Note 910 – Shareholder’s Equity

DP&L has 250,000,000 authorized shares of common stock, $0.01 par value, ~~common shares,~~ of which 41,172,173 are outstanding at September 30, ~~2016.~~2017. All common shares are held by DP&L’s parent, DPL.

As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio, calculated as total equity divided by total capitalization, of at least 50 percent and to not to have a negative retained earnings balance. After the fixed-asset ~~impairment~~impairments recorded ~~during the second quarter of~~in 2017 and 2016 and as of September 30, ~~2016,~~2017, DP&L's equity ratio was ~~50%~~39% and retained earnings balance was negative. It is unknown what impact, if any, this will have on DP&L. In the generation separation order dated September 17, 2014, the PUCO permitted DP&L to temporarily maintain long-term debt of $750.0 million or 75% of its rate base, whichever is greater, until January 1, 2018. After considering the payments and defeasance noted in Note 7 – Long-term Debt, DP&L's long-term debt is $659.9 million.

~~On October 13, 2016 (the "Redemption Date"),~~During the nine months ended September 30, 2017, DP&L ~~redeemed all~~paid $19.0 million in cash to DPL, which was treated as a return 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 incapital reducing Other paid-in capital. In addition, ~~DP&L’s~~DPL ~~Amended and Restated Articles of Incorporation, plus, in each case an amount equal~~made a $70.0 million capital contribution to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date: a price of $102.50 per share for the Series A Stock, a price of $103.00 per share for the Series B Stock, and a price of $101.00 per share for the Series C Stock. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of DP&L~~, except the right to payment of the redemption price, ceased to exist.~~

~~As we issued the notice to redeem the preferred stock in~~during 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.~~

~~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.~~2017.

Note 1011 – Contractual Obligations, Commercial Commitments and Contingencies

Equity Ownership Interest

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2040. ~~This would only happen if~~ OVEC could also seek additional contributions from us to avoid a default in the event that other OVEC members defaulted on ~~its debt payments.~~their respective OVEC obligations. As of September 30, ~~2016,~~2017, we have no knowledge of such a default.

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Commercial Commitments and Contractual Obligations

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,~~2017, cannot be reasonably determined.

Environmental Matters

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

The federal CAA and state laws and regulations (including State Implementation Plans) which require compliance, obtaining permits and reporting as to air emissions;


•	Rules and future rules issued by the USEPA, ~~and~~ the Ohio EPA or other authorities that require or will require substantial reductions in SO₂, particulates, mercury, acid gases, NOx, and other air emissions. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions;

Rules and future rules issued by the USEPA, the Ohio EPA or other authorities that require or will require reporting and reductions of GHGs;

~~Note 11 – Related Party Transactions~~In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.

~~Service Company~~

~~Effective January 1, 2014,~~We have several pending environmental matters associated with our coal-fired generation units. Some of these matters could have material adverse impacts on 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~~operation 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~~

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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~~Business Segments

~~During the second quarter of 2016, we tested the recoverability of our long-lived assets at certain of our generation facilities at~~Through September 30, 2017, DP&L~~. A ruling by~~ managed the ~~Supreme Court~~business through two reportable operating segments, the T&D segment and the Generation segment. After Generation Separation, DP&L will have only one reportable operating segment, the T&D segment, beginning on October 1, 2017. The primary segment performance measure is income / (loss) from operations before income tax as management has concluded that this measure best reflects the underlying business performance of ~~Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from~~DP&L and is the most ~~recent PJM capacity auction~~relevant measure considered in DP&L’s internal evaluation of the financial performance of its segments. The segments are discussed further below:

Transmission and Distribution Segment

The T&D segment is comprised primarily of DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. DP&L distributes electricity to more than 520,000 retail customers located in a ~~higher anticipated level~~6,000 square mile area of ~~environmental compliance~~West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses recording regulatory assets when incurred costs ~~resulting from third party studies were collectively determined~~are expected to be ~~an impairment indicator~~recovered in future customer rates and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were either closed or sold in prior periods. As these assets did not transfer to AES Ohio Generation on October 1, 2017 when DP&L’s generation separation occurred, they are grouped with the T&D assets for ~~these assets. We performed a long-lived asset impairment test~~segment reporting purposes. In addition, regulatory deferrals and ~~determined that~~collections, which include fuel deferrals in historical periods, are included in the ~~carrying amounts~~T&D segment.

Generation Segment

The Generation segment is comprised of DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. DP&L's Generation segment sells its generated energy and capacity into the wholesale market as DP&L sources all of the ~~asset groups of Stuart, Killen~~generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned multiple coal-fired 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.peaking electric generating facilities. As a result ~~we recognized asset impairment~~of Generation Separation, the DP&L-owned generating facilities were transferred to AES Ohio Generation on October 1, 2017, and DP&L will no longer have a Generation segment.

The accounting policies of the reportable segments are the same as those described in Note 1 – Overview and Summary of Significant Accounting Policies. Intersegment sales, costs of sales and expenses are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting segments.

The following tables present financial information for each of ~~$292.0 million, $246.2 million and $318.9 million for Stuart, Killen and Zimmer, respectively during the nine months ended September 30, 2016.~~DP&L’s reportable business segments:



$ in millions	T&D		Generation		Adjustments and Eliminations		DP&L Total
Three months ended September 30, 2017
Revenues from external customers	$	184.2	$	121.4	$	—	$	305.6
Intersegment revenues	—		—		—		—
Total revenues	$	184.2	$	121.4	$	—	$	305.6

Depreciation and amortization	$	19.6	$	3.1	$	—	$	22.7
Interest expense	$	7.7	$	—	$	—	$	7.7
Income from operations before income tax	$	20.0	$	21.2	$	—	$	41.2

Cash capital expenditures	$	20.6	$	4.2	$	—	$	24.8

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$ in millions	T&D		Generation		Adjustments and Eliminations		DP&L Total
Three months ended September 30, 2016
Revenues from external customers	$	215.8	$	152.6	$	—	$	368.4
Intersegment revenues	—		—		—		—
Total revenues	$	215.8	$	152.6	$	—	$	368.4

Depreciation and amortization	$	17.8	$	6.3	$	—	$	24.1
Interest expense	$	6.4	$	0.1	$	—	$	6.5
Income from operations before income tax	$	36.5	$	13.3	$	—	$	49.8

Cash capital expenditures	$	19.6	$	6.9	$	—	$	26.5



$ in millions	T&D		Generation			Adjustments and Eliminations		DP&L Total
Nine months ended September 30, 2017
Revenues from external customers	$	542.5	$	358.3		$	—	$	900.8
Intersegment revenues	—		—			—		—
Total revenues	$	542.5	$	358.3		$	—	$	900.8

Depreciation and amortization	$	56.3	$	11.9		$	—	$	68.2
Fixed-asset Impairments (Note 14)	$	—	$	66.3		$	—	$	66.3
Interest expense	$	22.9	$	0.2		$	—	$	23.1
Income / (loss) from operations before income tax	$	60.1	$	(56.3	)	$	—	$	3.8

Cash capital expenditures	$	66.3	$	16.1		$	—	$	82.4

At September 30, 2017
Total assets	$	1,655.3	$	178.0		$	—	$	1,833.3



$ in millions	T&D		Generation			Adjustments and Eliminations		DP&L Total
Nine months ended September 30, 2016
Revenues from external customers	$	605.4	$	425.9		$	—	$	1,031.3
Intersegment revenues	—		—			—		—
Total revenues	$	605.4	$	425.9		$	—	$	1,031.3

Depreciation and amortization	$	55.1	$	40.1		$	—	$	95.2
Fixed-asset Impairments (Note 14)	$	—	$	857.1		$	—	$	857.1
Interest expense	$	16.9	$	0.3		$	—	$	17.2
Income / (loss) from operations before income tax	$	98.5	$	(837.9	)	$	—	$	(739.4	)

Cash capital expenditures	$	61.8	$	36.5		$	—	$	98.3

At December 31, 2016
Total assets	$	1,710.5	$	324.6		$	—	$	2,035.1

Note 13 – Assets and Liabilities Held for Sale

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adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs prior to closing. The sale is subject to approval by the FERC and is expected to close in the fourth quarter of 2017.

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



$ in millions	September 30, 2017
Assets
Accounts receivable, net ^(a)	$	(11.2	)
Inventories	22.7
Property, plant & equipment, net	44.8
Other prepayments and current assets	0.7
Total assets of the disposal group classified as held for sale in the balance sheet	$	57.0

Liabilities
Accounts payable	$	0.7
Accrued taxes	2.6
Asset retirement obligations	3.4
Other liabilities ^(b)	(0.7		)
Total liabilities of the disposal group classified as held for sale in the balance sheet	$	6.0


(a)	Represents credit balances netted in Accounts Receivable, due to the right of offset with partners


(b)	Represents amounts due to (from) partners for pension benefits associated with partner-operated plants

Zimmer Station and Miami Fort Station's results are reflected within continuing operations in the Condensed Statements of Operations. The combined income / (loss) from continuing operations before income tax for Zimmer Station and Miami Fort Station was $11.0 million and $1.9 million for the three months ended September 30, 2017 and 2016, respectively, and $18.9 million and $(333.5) million for the nine months ended September 30, 2017 and 2016, respectively. Zimmer Station and Miami Fort Station are included in the Generation segment.

~~Item 2~~Note 14 – ~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~Fixed-asset Impairments

~~This report includes~~On March 17, 2017, the ~~combined filing~~Board 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~~Directors of DP&L ~~included in~~ ~~Part I – Financial Information~~,approved 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~~retirement of the ~~2016 U.S. elections could result in significant changes to U.S. environmental policies, energy policies~~two DP&L operated and ~~tax laws,~~co-owned electric generating stations; the ~~impact~~Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine (collectively, the “Facilities”) on or before June 1, 2018. The co-owners of ~~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,~~agreed 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 beproceed with this plan of retirement. We performed a ~~PRP for~~long-lived asset impairment analysis and determined that 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~~carrying amounts of the ~~site, it could~~Facilities were not recoverable. The asset groups of Stuart Station and Killen Station were determined to have fair values of $3.3 million and $7.9 million, respectively, using the discounted cash flows under the income approach. As a ~~material adverse effect on its business, financial condition or results~~result, we recognized asset impairment expense of ~~operations.~~$39.0 million and $27.3 million for Stuart Station and Killen Station, respectively.

~~On April 7, 2010,~~Additionally, as a result of the ~~USEPA published an Advance Notice~~decision to retire the Facilities by June 1, 2018, we concluded that inventory at these Facilities is considered obsolete. As a result, we recognized a loss on disposal of ~~Proposed Rulemaking announcing that it~~$9.8 million and $6.4 million for Stuart Station and Killen Station inventories, respectively, during the first quarter of 2017, which is ~~reassessing existing regulations governing the use and distribution~~recorded in ~~commerce of polychlorinated biphenyls (PCBs). This reassessment is~~Loss on asset disposal 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~~Condensed Statements 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.Operations.

~~At present,~~ ~~DP&L~~ ~~is unable to project whether~~During the ~~CP program will be beneficial or negative to~~ ~~DP&L’s~~ ~~operations, but~~second quarter of 2016, we tested the ~~results could be material to~~ ~~DP&L’s~~ ~~results~~recoverability 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~~our long-lived assets at 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 effectour generation facilities 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 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 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 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 $0.6 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. 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~~We performed a long-lived asset impairment ~~test~~analysis 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.~~

~~Table of Contents~~

~~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 million primarily 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 million primarily 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 million primarily 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 million primarily 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 million primarily 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~~amount of the asset groups of Stuart, Killen and Zimmer were not recoverable. ~~For more information, see Note 12 – Fixed-asset Impairment~~The asset groups of ~~Notes~~Stuart, Killen and Zimmer were determined to ~~DP&L's~~ ~~Condensed Financial Statements.~~

~~DP&L – Charge for Early Redemption~~have fair values of ~~Debt~~

~~During the three and nine months ended September 30, 2016, the charge for early redemption of debt decreased $4.5~~$164.4 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~~$84.3 million and ~~$7.4~~$111.0 million, respectively, ~~compared to~~using the ~~same periods in~~discounted cash flows under 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~~income approach. As a result, we recognized asset impairment expense of $292.0 million, $246.2 million 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~~$318.9 million ~~compared to the same period in the prior year primarily due to higher pre-tax income~~for Stuart, Killen and ~~an anticipated refund from the IRS for the filing, in the prior year, of an amended 2011 tax return for the predecessor company.~~Zimmer, respectively.

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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 activities decreased $61.8 million to $198.6 million in the nine months ended September 30, 2016 from $260.4 million in the nine months ended September 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 activities decreased $27.3 million to $220.4 million in the nine months ended September 30, 2016 from $247.7 million in the nine months ended September 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 activities decreased $66.1 million to $(23.1) million in the nine months ended September 30, 2016 from $(89.2) million, in the nine months ended September 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 activities increased $2.7 million to $(86.6) million in the~~nine months ended September 30, 2016 from $(83.9) million in the nine months ended September 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 ended September 30, 2016 compared to $(145.2) million from financing activities for the nine months ended September 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 ended September 30, 2016 compared to $(158.5) million in the nine months ended September 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 ended September 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’s~~ ~~EBITDA 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 ended September 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 SO₂ ~~allowances for 2016, however, the exact consumption of SO~~₂ allowances will depend on market prices for power, availability of our generation units and the actual sulfur content of the coal burned. We may purchase some 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~~

~~Table of Contents~~

~~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~~

~~Table of Contents~~

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

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

The following discussion contains forward-looking statements and should be read in conjunction with the accompanying Condensed Consolidated Financial Statements and related footnotes of DPL and the Condensed Financial Statements and related footnotes of DP&L included in Part I – Financial Information, the risk factors in Item 1A to Part I of our Form 10-K for the fiscal year ended December 31, 2016 and in Item 1A to Part II of this Quarterly Report on Form 10-Q, and our “Forward-Looking Statements” section of this Form 10-Q. For a list of certain abbreviations or acronyms in this discussion, see the Glossary at the beginning of this Form 10-Q.

Key topics in Management's Discussion and Analysis

Our discussion covers the following:

Review of Results of Operations


◦	DPL


▪	DPL - T&D Segment


▪	DPL - Generation Segment


◦	DP&L


▪	DP&L - T&D Segment


▪	DP&L - Generation Segment

Key Trends and Uncertainties

Capital Resources and Liquidity

Market Risk

Critical Accounting Estimates

REGULATORY ENVIRONMENT

DPL’s, DP&L’s and our other subsidiaries’ facilities and operations are subject to a wide range of regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities and operations in an effort to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable and can be reasonably estimated. See Note 10 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DPL’s Condensed Consolidated Financial Statements and Note 11 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DP&L’s Condensed Financial Statements. In addition to matters discussed or updated herein, our Forms 10-K and 10-Q previously filed with the SEC during 2017 describe other regulatory matters which have not materially changed since those filings.

ENVIRONMENTAL MATTERS

In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities and operations to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies for environmental matters as of September 30, 2017. We have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or cannot be reasonably estimated. Of these, those that we believe are most likely to have a material effect are disclosed in our 2016 10-K. We evaluate the potential liability related to environmental matters quarterly and may revise our accruals. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.

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

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

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

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

PJM PRICING

Capacity Auction Price

The PJM capacity base residual auction for the 2020/21 period cleared at a per megawatt price of $77/MW-day for our RTO area. The per megawatt prices for the periods 2019/20, 2018/19, 2017/18 and 2016/17 were $100/MW-day, $165/MW-day, $152/MW-day and $134/MW-day, respectively, based on previous auctions. As discussed in our Form 10-K, the CP program, which was previously approved by the FERC, will phase out RPM as of the 2018/19 period. We cannot predict the outcome of future auctions but based on actual results attained, we estimate that a hypothetical increase or decrease of $10/MW-day in the capacity auction price would result in an annual impact to net income of approximately $5.7 million and $4.8 million for DPL and DP&L, respectively. These estimates do not, however, take into consideration the other factors that may affect the impact of capacity revenues and costs on net income such as our generation capacity and the levels of wholesale revenues. These estimates are discussed further within Commodity Pricing Risk under the Market Risk section of this Management Discussion & Analysis.

OHIO COMPETITION AND REGULATORY PROCEEDINGS

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

On November 30, 2015, DP&L filed a distribution rate case using a 12-month test year of June 1, 2015 to May 31, 2016 to measure revenue and expenses and a date certain of September 30, 2015 to measure its asset base. DP&L is seeking an increase to distribution revenues of $65.0 million per year. DP&L has asked for recovery of certain regulatory assets as well as two new riders that would allow DP&L to recover certain costs on an ongoing basis. It has proposed a modified rate design, which would increase the monthly customer charge, in an effort to decouple distribution revenues from electric sales. If approved as filed, the rates are expected to have an effect of approximately 4% on a typical residential customer bill based on rates in effect at the time of the filing.

Ohio law requires that all Ohio distribution utilities file either an ESP or MRO to establish rates for SSO service. For a discussion of the current status of DP&L's ESPs, please see Note 3 – Regulatory Matters of Notes to DPL's Condensed Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L's Condensed Financial Statements.

Ohio law and PUCO rules contain targets relating to renewable energy, peak demand reduction and energy efficiency standards. If any targets are not met, compliance penalties will apply unless the PUCO makes certain findings that would excuse performance. DP&L is in full compliance with energy efficiency, peak demand reduction and renewable targets. In 2016, DP&L filed a new energy efficiency portfolio plan which was ultimately settled. The settlement agreement extended the current plan and allowed DP&L to continue to collect lost distribution revenues. The settlement agreement was approved by the PUCO in September 2017. On June 15, 2017, DP&L filed a new energy efficiency portfolio plan for programs in years 2018 through 2020. On October 27, 2017, DP&L filed an unopposed Stipulation and Recommendation in that case which expands the programs offered, the overall budget and opportunities for shared savings. Lost distribution revenues will be collected in a new rider established in DP&L's ESP 3. This Stipulation is pending PUCO approval.

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DP&L and AES Ohio Generation filed applications before the FERC to adjust their rates with respect to reactive power provided to PJM from their generation units. On March 3, 2017, DP&L, AES Ohio Generation, and certain intervening parties filed an Offer of Settlement that was approved by the FERC on May 16, 2017. The changes from current reactive power rates were not material. Effective October 1, 2017, FERC approved the transfer of the reactive power rates attributable to generation facilities that had been owned by DP&L to the AES Ohio Generation reactive power tariff. Additionally, the FERC has referred to FERC’s Office of Enforcement for investigation of an issue regarding reactive power charges under the previously effective rates in light of changes in DP&L’s generation portfolio. DP&L's reactive power rates were last reset in 1998. As of the date of this report, DP&L is unable to predict the ultimate outcome of the investigation. Several other utilities within PJM are also being investigated by FERC’s Office of Enforcement on the same issue of changes in the generation portfolio that occurred in between rate proceedings.

Effective October 1, 2017, DP&L completed the separation of its generation assets, which ultimately transferred them to AES Ohio Generation as part of the Generation Separation transactions.

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RESULTS OF OPERATIONS HIGHLIGHTS – DPL

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



	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2017			2016			2017			2016
Revenues:
Retail	$	163.8		$	197.4		$	487.1		$	553.1
Wholesale	102.2			138.3			299.8			368.0
RTO revenues	15.3			16.8			43.7			47.2
RTO capacity revenues	39.8			32.9			106.6			104.6
Other revenues	2.8			3.9			8.7			8.7
Total revenues	323.9			389.3			945.9			1,081.6
Cost of revenues:
Fuel cost:
Fuel	57.6			80.4			166.3			210.9
Gains from the sale of coal	(0.3		)	(1.9		)	(0.9		)	(4.9		)
Mark-to-market losses	—			0.4			—			—
Net fuel cost	57.3			78.9			165.4			206.0
Purchased power:
Purchased power	63.2			86.1			200.4			254.5
RTO charges	15.8			23.2			53.3			60.2
RTO capacity charges	3.8			3.6			10.7			18.5
Mark-to-market losses / (gains)	1.2			(1.2		)	(1.0		)	(2.7		)
Net purchased power cost	84.0			111.7			263.4			330.5
Total cost of revenues	141.3			190.6			428.8			536.5

Gross margin	182.6			198.7			517.1			545.1

Operating expenses:
Operation and maintenance	81.9			91.5			250.3			257.2
Depreciation and amortization	27.3			30.9			81.8			100.3
General taxes	20.1			21.6			68.3			64.2
Fixed-asset impairment	—			—			66.4			235.5
Loss / (gain) on asset disposal	(0.3		)	—			15.9			0.1
Other	(5.2		)	(0.7		)	(6.1		)	(0.7		)
Total operating expenses	123.8			143.3			476.6			656.6

Operating income / (loss)	58.8			55.4			40.5			(111.5		)

Other income / (expense), net:
Investment income	0.1			0.1			0.2			0.3
Interest expense	(27.2		)	(27.0		)	(81.5		)	(79.3		)
Charge for early redemption of debt	(3.0		)	(0.5		)	(3.3		)	(3.1		)
Other expense	(0.7		)	(0.2		)	(2.3		)	(0.9		)
Total other expense, net	(30.8		)	(27.6		)	(86.9		)	(83.0		)

Income / (loss) from continuing operations before income tax (a)	$	28.0		$	27.8		$	(46.4	)	$	(194.5	)


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

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DPL – Revenues

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



	Three months ended September 30,		Nine months ended September 30,
	2017	2016	2017	2016
Heating degree days ^(a)	78	31	2,763	3,212
Cooling degree days ^(a)	584	874	862	1,175

(a)

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

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

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



	Three months ended			Nine months ended
	September 30,			September 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Retail
Rate	$	(17.0	)	$	(35.2	)
Volume	(15.5		)	(34.1		)
Other miscellaneous	(1.1		)	3.3
Total retail change	(33.6		)	(66.0		)

Wholesale
Rate	(8.8		)	(25.2		)
Volume	(27.3		)	(43.0		)
Total wholesale change	(36.1		)	(68.2		)

RTO revenues and RTO capacity revenues
RTO revenues and RTO capacity revenues	5.4			(1.5		)

Other
Other revenues	(1.1		)	—

Total revenues change	$	(65.4	)	$	(135.7	)

During the three months ended September 30, 2017, Revenues decreased $65.4 million to $323.9 million from $389.3 million in the same period of the prior year. This decrease was primarily the result of the components of revenue discussed below:

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recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as cooling degree days decreased by 290 degree days. The aforementioned impacts resulted in an unfavorable $17.0 million retail price variance and an unfavorable $15.5 million retail volume variance. In addition, there was an unfavorable other miscellaneous variance of $1.1 million.

Wholesale revenues decreased $36.1 million primarily as a result of an unfavorable $27.3 million wholesale volume variance and an unfavorable $8.8 million wholesale price variance. The unfavorable price variance was due to lower PJM market prices in the third quarter of 2017 and lower realized gains on derivatives. The decrease in wholesale volumes of $27.3 million was primarily driven by a decrease in the load served of other parties through their competitive bid process, as well as a 20% decrease in internal generation at DPL's plants in 2017.

RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and PJM capacity payments, increased $5.4 million compared to the same period in the prior year. This increase was the result of a $6.9 million increase in revenue realized from the PJM capacity auction in 2017 due to higher prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016. This increase was partially offset by a $1.5 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves.

During the nine months ended September 30, 2017, Revenues decreased $135.7 million to $945.9 million from $1,081.6 million in the same period of the prior year. This decrease was primarily the result of the components of revenue discussed below:

Retail revenues decreased $66.0 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, collections on the remaining 2015 deferred fuel balance in the first quarter of 2016, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree days decreased by 449 degree days and cooling degree days decreased by 313 degree days. The aforementioned impacts resulted in an unfavorable $35.2 million retail price variance and an unfavorable $34.1 million retail volume variance. These variances were partially offset by a favorable other miscellaneous variance of $3.3 million.

Wholesale revenues decreased $68.2 million primarily as a result of an unfavorable $43.0 million wholesale volume variance and an unfavorable $25.2 million wholesale price variance. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes of $43.0 million was primarily driven by a decrease in the load served of other parties through their competitive bid process and a 10% decrease in internal generation at DPL's plants in 2017.

RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and PJM capacity payments, decreased $1.5 million compared to the same period in the prior year. This decrease was the result of a $3.5 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves. This decrease was partially offset by a $2.0 million increase in revenue realized from the PJM capacity auction in 2017 primarily due to higher average prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016, and $136/MW-day in June of 2015.

DPL – Cost of Revenues

During the three months ended September 30, 2017, Cost of revenues decreased $49.3 million compared to the same period in the prior year:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $21.6 million compared to the same period in the prior year primarily due to a 10% decrease in average fuel cost per MWh and a 20% decrease in internal generation.

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Net purchased power decreased $27.7 million compared to the same period in the prior year. This change was driven by the following factors:

◦

Purchased power decreased $22.9 million primarily due to a $11.3 million volume decrease and an $11.6 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 than 2016 and lower PJM market rates.

◦

RTO charges decreased $7.4 million compared to the same period in the prior year primarily due to lower transmission and congestion charges. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within our network, which are incurred and charged to customers in the transmission rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.


◦	RTO capacity charges increased $0.2 million compared to the same period in the prior year primarily due to increases in RTO capacity prices. As noted above, RTO capacity prices are set by an annual auction. The increase in RTO capacity prices was partially offset by a lower retail load served in 2017. Retail load served relates to the load of other parties through their competitive bid process.


◦	Mark-to-market losses increased $2.4 million due to changes in power prices in 2017 and 2016.

During the nine months ended September 30, 2017, Cost of revenues decreased $107.7 million compared to the same period in the prior year:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $40.6 million compared to the same period in the prior year primarily due to a 13% decrease in average fuel cost per MWh and a 10% decrease in internal generation. There were fuel costs deferred in 2015, which were expensed in 2016 because they were collected in 2016, which contributed to the price decrease. There were no fuel costs deferred or collected in the first nine months of 2017.

Net purchased power decreased $67.1 million compared to the same period in the prior year. This decrease was driven by the following factors:

◦

Purchased power decreased $54.1 million primarily due to a $35.8 million volume decrease and an $18.3 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 than 2016.

◦

RTO charges decreased $6.9 million compared to the same period in the prior year primarily due to lower transmission and congestion charges. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within our network, which are incurred and charged to customers in the transmission rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.

◦

RTO capacity charges decreased $7.8 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted above, RTO capacity prices are set by an annual auction.


◦	Mark-to-market gains decreased $1.7 million due to changes in power prices in 2017 and 2016.

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DPL – Operation and Maintenance

During the three and nine months ended September 30, 2017, Operation and Maintenance expense decreased $9.6 million and $6.9 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:



	Three months ended			Nine months ended
	September 30,			September 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)	$	(6.3	)	$	(18.4	)
Decrease in generating facilities operating and maintenance expenses	(6.6		)	(3.5		)
Increase in group insurance expense associated with participation in the AES self-insurance plan	—			7.3
Increase in retirement benefits costs, primarily due to pension curtailment charges associated with announced plant closures in the first quarter of 2017	0.8			6.2
Increase in legal and other consulting costs	1.1			2.8
Other, net	1.4			(1.3		)
Net change in operation and maintenance expense	$	(9.6	)	$	(6.9	)


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

DPL – Depreciation and Amortization

During the three months ended September 30, 2017, Depreciation and amortization decreased $3.6 million, compared to the same period in the prior year. The decrease was primarily the result of the fixed-asset impairments in the fourth quarter of 2016 and the first quarter of 2017, which reduced depreciation expense due to lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fort and Zimmer depreciation expense due to the pending sale of these two plants.

During the nine months ended September 30, 2017, Depreciation and amortization decreased $18.5 million, compared to the same period in the prior year. The decrease was primarily a result of the fixed-asset impairments in the second and fourth quarters of 2016, and the first quarter of 2017, which reduced depreciation expense due to the lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fort and Zimmer depreciation expense due to the pending sale of these two plants.

DPL – General Taxes

During the three months ended September 30, 2017, General taxes decreased $1.5 million compared to the same period in the prior year. The decrease was primarily the result of a true-up of the year to date 2017 Ohio property tax accrual to reflect final assessments for 2017 taxes.

During the nine months ended September 30, 2017, General taxes increased $4.1 million compared to the same period in the prior year. The increase was primarily the result of lower Ohio property tax expense in 2016 due to a $1.6 million favorable true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016 and a 2017 unfavorable true-up of $1.2 million for the 2016 Ohio property tax accrual to reflect actual payments made in 2017, as well as higher Ohio property tax rates in 2017.

DPL – Fixed-asset Impairment

During the nine months ended September 30, 2017, DPL recorded an impairment of fixed-assets of $66.4 million. DPL recognized asset impairment expense of $39.1 million and $27.3 million for Stuart Station and Killen Station, respectively. For more information, see Note 14 – Fixed-asset Impairments of Notes to DPL's Condensed Consolidated Financial Statements.

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

DPL – Loss (Gain) on Asset Disposal

During the nine months ended September 30, 2017, DPL recorded a loss on asset disposal of $15.9 million primarily related to the write-off of plant materials and supplies inventory at the Stuart and Killen plants.

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DPL – Other

During the three and nine months ended September 30, 2017, Other operating expenses were reduced by $4.5 million and $5.4 million, respectively, primarily due to insurance recoveries recorded in 2017.

DPL – Charge for Early Redemption of Debt

During the three and nine months ended September 30, 2017, DPL recorded a charge for early redemption of debt of $3.0 million and $3.3 million, respectively, primarily due to the early redemption of the 4.8% Tax-exempt First Mortgage Bonds due 2036.

During the three and nine months ended September 30, 2016, DPL recorded a charge for early redemption of debt of $0.5 million and $3.1 million, respectively. The $3.1 million charge was primarily due to the February 2016 make-whole premium of $2.4 million associated with the early redemption of $73.0 million of the 6.5% Senior Notes due in 2016.

DPL – Income Tax Expense

During the three months ended September 30, 2017, Income tax expense decreased $6.6 million compared to the same period in the prior year primarily due to a year-to-date adjustment for the decrease in the annualized effective rate.

During the nine months ended September 30, 2017, Income tax benefit decreased $57.9 million compared to the same period in the prior year primarily due to a significantly larger pre-tax loss in the prior year versus the current year.

RESULTS OF OPERATIONS BY SEGMENT – DPL Inc.

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

Transmission and Distribution Segment

The T&D segment is comprised primarily of DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. DP&L distributes electricity to more than 520,000 retail customers located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses recording regulatory assets when incurred costs are expected to be recovered in future customer rates and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were either closed or sold in prior periods. As these assets did not transfer to AES Ohio Generation on October 1, 2017 when DP&L’s generation separation occurred, they are grouped with the T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment.

Generation Segment

The Generation segment is comprised of AES Ohio Generation and DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. Through September 30, 2017, AES Ohio Generation owned and operated peaking generating facilities, and DP&L owned multiple coal-fired and peaking electric generating facilities. As a result of Generation Separation, the DP&L-owned generating facilities were transferred to AES Ohio Generation on October 1, 2017.

Included within the “Other” column are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs, which include interest expense on DPL’s long-term debt and adjustments related to purchase accounting from the Merger. The accounting policies of the reportable segments are the same as those described in Note 1 – Overview and Summary of Significant Accounting Policies.

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

See Note 11 – Business Segments of Notes to DPL’s Condensed Consolidated Financial Statements for additional information regarding DPL’s reportable segments.

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



	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2017			2016			2017			2016
T&D	$	20.0		$	36.4		$	60.1		$	97.9
Generation	29.9			14.2			(43.7		)	(857.2		)
Other	(21.9		)	(22.8		)	(62.8		)	564.8
Income / (loss) from continuing operations before income tax (a)	$	28.0		$	27.8		$	(46.4	)	$	(194.5	)


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

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



	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2017			2016			2017			2016
Revenues:
Retail	$	164.0		$	197.6		$	487.8		$	553.9
Wholesale	5.9			5.3			14.5			12.3
RTO revenues	12.5			11.5			35.5			34.2
RTO capacity revenues	1.8			1.4			4.7			5.0
Total revenues	184.2			215.8			542.5			605.4
Cost of revenues:
Net fuel cost	—			—			—			5.3
Purchased power:
Purchased power	58.2			73.9			178.2			199.9
RTO charges	15.7			15.7			43.2			44.3
RTO capacity charges	0.5			0.2			0.6			(0.2		)
Net purchased power cost	74.4			89.8			222.0			244.0
Total cost of revenues	74.4			89.8			222.0			249.3

Gross margin	109.8			126.0			320.5			356.1

Operating expenses:
Operation and maintenance	42.4			47.3			121.4			134.9
Depreciation and amortization	19.6			17.8			56.3			55.1
General taxes	19.3			17.7			57.8			50.7
Gain on asset disposal	(0.3		)	—			(0.3		)	(0.4		)
Total operating expenses	81.0			82.8			235.2			240.3

Operating income	28.8			43.2			85.3			115.8

Other expense, net
Investment income	0.1			0.1			0.2			0.3
Interest expense	(7.7		)	(6.5		)	(22.9		)	(17.5		)
Charge for early redemption of debt	(1.0		)	(0.5		)	(1.1		)	(0.5		)
Other expense	(0.2		)	0.1			(1.4		)	(0.2		)
Total other expense, net	(8.8		)	(6.8		)	(25.2		)	(17.9		)

Income from continuing operations before income tax (a)	$	20.0		$	36.4		$	60.1		$	97.9


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

DPL Inc. –T&D Segment – Revenues

During the three months ended September 30, 2017, the segment’s revenues decreased $31.6 million to $184.2 million from $215.8 million in the same period of the prior year. This decrease was primarily the result of lower retail volumes and lower average retail rates.

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recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as cooling degree days decreased by 290 degree days. The aforementioned impacts resulted in an unfavorable $15.5 million retail volume variance and an unfavorable $17.0 million retail price variance. In addition, there was an unfavorable other miscellaneous variance of $1.1 million.

Wholesale revenues increased $0.6 million. These revenues, included in the T&D segment, consist of our 4.9% share of the generation output of OVEC, which is sold into PJM at market prices.

RTO capacity and other revenues increased $1.4 million compared to the same period in the prior year.

During the nine months ended September 30, 2017, the segment’s revenues decreased $62.9 million to $542.5 million from $605.4 million in the same period of the prior year. This decrease was primarily the result of lower retail volumes and lower average retail rates.

Retail revenues decreased $66.1 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, collections on the remaining 2015 deferred fuel balance in the first quarter of 2016, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree days decreased by 449 degree days and cooling degree days decreased by 313 degree days. The aforementioned impacts resulted in an unfavorable $35.2 million retail price variance and an unfavorable $34.1 million retail volume variance. These variances were partially offset by a favorable other miscellaneous variance of $3.2 million.

Wholesale revenues increased $2.2 million. These revenues, included in the T&D segment, consist of our 4.9% share of the generation output of OVEC, which is sold into PJM at market prices. As such, the increase in wholesale revenue is due to increased OVEC revenue.

RTO capacity and other revenues increased $1.0 million compared to the same period in the prior year.

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

During the three months ended September 30, 2017, Total cost of revenues decreased $15.4 million compared to the prior year. This decrease was a result of:

Net purchased power decreased $15.4 million compared to the prior year. This was driven by the following factors:


◦	Purchased power decreased $15.7 million compared to the same period in the prior year primarily due to a favorable price variance of $7.4 million driven by lower rates in the competitive bid process in 2017, and lower volumes of $8.3 million due to the decrease in DP&L retail demand in 2017.


◦	RTO capacity and other charges increased $0.3 million compared to the same period in the prior year.

During the nine months ended September 30, 2017, Total cost of revenues decreased $27.3 million compared to the prior year. This decrease was a result of:

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

Net purchased power decreased $22.0 million compared to the prior year. This was driven by the following factors:


◦	Purchased power decreased $21.7 million compared to the same period in the prior year primarily due to a favorable price variance of $8.5 million driven by lower rates in the competitive bid process in 2017, and lower volumes of $13.2 million due to the decrease in DP&L retail demand in 2017.


◦	RTO capacity and other charges decreased $0.3 million compared to the same period in the prior year.

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DPL Inc. –T&D Segment – Operating Expenses

During the three and six months ended June 30, 2017, Operating expenses decreased $1.8 million and $5.1 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:



	Three months ended			Nine months ended
	September 30,			September 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider ^(a)	$	(6.3	)	$	(18.4	)
Increase in General taxes ^(b)	1.6			7.1
Increase / (decrease) in group insurance expense associated with participation in the AES self-insurance plan	(0.1		)	3.4
Increase in legal and other consulting costs	0.5			2.5
Increase in Depreciation and amortization expense primarily due to additional investments in T&D fixed assets	1.8			1.2
Other, net	0.7			(0.9		)
Net change in operating expenses	$	(1.8	)	$	(5.1	)


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

(b)

During the three months ended September 30, 2017, General taxes increased $1.6 million compared to the same period in the prior year. The increase was primarily the result of higher Ohio property tax expense driven by higher tax rates and property values. During the nine months ended September 30, 2017, General taxes increased $7.1 million compared to the same period in the prior year. The increase was primarily the result of higher Ohio property tax expense driven by higher tax rates, higher property values, lower expense in 2016 due to a $1.6 million favorable true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016, and a 2017 unfavorable true-up of $1.2 million for the 2016 Ohio property tax accrual to reflect actual payments made in 2017.

DPL Inc. –T&D Segment – Interest Expense

During the three months ended September 30, 2017, Interest expense increased $1.2 million compared to the same period in the prior year primarily driven by higher interest rates on the $445.0 million variable rate Term Loan B maturing on August 24, 2022 compared to the interest rate on the 1.875% First Mortgage Bonds Due 2016.

During the nine months ended September 30, 2017, Interest expense increased $5.4 million compared to the same period in the prior year primarily driven by higher interest rates on the $445.0 million variable rate Term Loan B maturing on August 24, 2022 compared to the interest rate on the 1.875% First Mortgage Bonds Due 2016.

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Statement of Operations Highlights–DPL Inc. – Generation Segment



	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2017			2016			2017			2016
Revenues:
Retail	$	0.1		$	0.1		$	0.2		$	0.2
Wholesale	96.3			133.6			286.1			357.3
RTO revenues	2.8			5.3			8.2			13.0
RTO capacity revenues	38.0			31.5			101.9			99.6
Other mark-to-market losses	—			(0.1		)	—			(0.1		)
Total revenues	137.2			170.4			396.4			470.0
Cost of revenues:
Fuel cost:
Fuel	57.6			80.4			166.3			205.3
Losses from the sale of coal	(0.3		)	(1.9		)	(0.9		)	(4.6		)
Mark-to-market losses	—			0.4			—			—
Net fuel cost	57.3			78.9			165.4			200.7
Purchased power:
Purchased power	4.6			11.2			21.8			54.6
RTO charges	0.1			7.5			10.1			15.9
RTO capacity charges	3.3			3.4			10.1			18.7
Mark-to-market losses / (gains)	1.2			(1.2		)	(1.0		)	(2.7		)
Net purchased power cost	9.2			20.9			41.0			86.5
Total cost of revenues	66.5			99.8			206.4			287.2

Gross margin	70.7			70.6			190.0			182.8

Operating expenses:
Operation and maintenance	40.3			45.5			130.0			124.8
Depreciation and amortization	4.7			7.7			16.6			44.6
General taxes	0.9			3.8			10.4			13.4
Fixed-asset impairment	—			—			66.3			857.1
Loss / (gain) on asset disposal	—			(0.7		)	16.2			(0.2		)
Other	(5.2		)	—			(6.1		)	—
Total operating expenses	40.7			56.3			233.4			1,039.7

Operating income / (loss)	30.0			14.3			(43.4		)	(856.9		)

Other expense, net
Interest expense	—			(0.1		)	(0.2		)	(0.3		)
Other expense	(0.1		)	—			(0.1		)	—
Total other expense, net	(0.1		)	(0.1		)	(0.3		)	(0.3		)

Income / (loss) from continuing operations before income tax (a)	$	29.9		$	14.2		$	(43.7	)	$	(857.2	)


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

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DPL Inc. –Generation Segment – Revenues

During the three months ended September 30, 2017, the segment’s revenues decreased $33.2 million to $137.2 million from $170.4 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes and lower average wholesale rates, partially offset by higher RTO capacity and other revenues.

Wholesale revenues decreased $37.3 million primarily as a result of an unfavorable wholesale volume variance of $33.2 million and an unfavorable wholesale price variance of $4.1 million. The unfavorable price variance was due to lower PJM market prices in the third quarter of 2017 and lower realized gains on derivatives. The decrease in wholesale volumes was primarily driven by a decrease in the load served of other parties through their competitive bid process, as well as a 20% decrease in internal generation at DPL's plants in 2017.

RTO capacity and other revenues, consisting primarily of PJM capacity revenues, regulation services, reactive supply and operating reserves, increased $4.0 million compared to the same period in the prior year. This increase was the result of a $6.5 million increase in revenue realized from the PJM capacity auction in 2017 due to higher prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016. This increase was partially offset by a $2.5 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves.

During the nine months ended September 30, 2017, the segment’s revenues decreased $73.6 million to $396.4 million from $470.0 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes, lower average wholesale rates, and lower RTO capacity and other revenues.

Wholesale revenues decreased $71.2 million primarily as a result of an unfavorable wholesale volume variance of $48.7 million and an unfavorable wholesale price variance of $22.5 million. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes was primarily driven by a decrease in the load served of other parties through their competitive bid process and a 10% decrease in internal generation at DPL's plants in 2017.

RTO capacity and other revenues, consisting primarily of PJM capacity revenues, regulation services, reactive supply and operating reserves, decreased $2.5 million compared to the same period in the prior year primarily due to a $4.8 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves. This decrease was partially offset by a $2.3 million increase in revenue realized from the PJM capacity auction in 2017 primarily due to higher average prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016, and $136/MW-day in June of 2015.

DPL Inc. –Generation Segment – Cost of Revenues

During the three months ended September 30, 2017, Total cost of revenues decreased $33.3 million compared to the prior year. This decrease was a result of:

Net purchased power decreased $11.7 million compared to the prior year. This decrease was driven by the following factors:

◦

Purchased power decreased $6.6 million primarily due to a favorable volume variance of $3.5 million and a favorable price variance of $3.1 million. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016. The price decrease was primarily driven by lower PJM market rates in the third quarter of 2017. The generation segment purchases power to source retail load in other service territories and to meet contracted Wholesale requirements when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

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◦	RTO charges decreased $7.4 million compared to the same period in the prior year primarily due to lower transmission and congestion charges.


◦	RTO capacity charges decreased $0.1 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, partially offset by higher RTO capacity prices. Retail load served relates to the load of other parties through their competitive bid process.


◦	Mark-to-market losses increased $2.4 million due to changes in power prices in 2017 and 2016.

During the nine months ended September 30, 2017, Total cost of revenues decreased $80.8 million compared to the prior year. This decrease was a result of:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $35.3 million compared to the same period in the prior year primarily due to a 13% decrease in average fuel cost per MWh and a 10% decrease in internal generation.

Net purchased power decreased $45.5 million compared to the prior year. This decrease was driven by the following factors:

◦

Purchased power decreased $32.8 million primarily due to a favorable volume variance of $29.9 million and a favorable price variance of $2.9 million. The decrease in volume was driven by a lower load served of other parties through their competitive bid process in 2017. The price decrease was primarily driven by lower PJM market rates. The generation segment purchases power to source retail load in other service territories and to meet contracted Wholesale requirements when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.


◦	RTO charges decreased $5.8 million compared to the same period in the prior year primarily due to lower transmission and congestion charges.

◦

RTO capacity charges decreased $8.6 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted above, RTO capacity prices are set by an annual auction.


◦	Mark-to-market gains decreased $1.7 million due to changes in power prices in 2017 and 2016.

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DPL Inc. –Generation Segment �� Operating Expenses

During the three and six months ended June 30, 2017, Operating expenses decreased $15.6 million and $806.3 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:



	Three months ended			Nine months ended
	September 30,			September 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Change in Fixed-asset impairment from 2016 to 2017 ^(a)	$	—		$	(790.8	)
Decrease in Depreciation and amortization expense as a result of the fixed-asset impairments in the second and fourth quarters of 2016 and the first quarter of 2017, which reduced depreciation expense due to the lower asset values	(3.0		)	(28.0		)
Higher insurance recoveries in 2017	(5.2		)	(6.1		)
Decrease in General taxes due to a true-up of the year to date 2017 Ohio property tax accrual for generation to reflect final assessments for 2017 taxes recorded in the third quarter of 2017	(2.9		)	(3.0		)
Decrease in generating facilities operating and maintenance expenses	(5.6		)	(2.4		)
Loss on asset disposal ^(b)	0.7			16.4
Increase / (decrease) in retirement benefit costs, primarily due to pension curtailment charges associated with announced plant closures in the first quarter	(0.1		)	5.6
Increase in group insurance expenses associated with participation in the AES self-insurance plan	0.1			3.9
Other, net	0.4			(1.9		)
Net change in operating expenses	$	(15.6	)	$	(806.3	)

(a)

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


(b)	During the nine months ended September 30, 2017, the Generation segment recorded a loss on asset disposal of $15.9 million primarily related to the write-off of plant materials and supplies inventory at the Stuart and Killen plants.

DPL Inc. –Generation Segment – Interest Expense

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

In the generation separation order dated September 17, 2014, the PUCO permitted DP&L, upon transfer of the generation assets to AES Ohio Generation, to temporarily maintain long-term debt of $750.0 million or 75% of its rate base, whichever is greater, until January 1, 2018. The order also stated if DP&L cannot rebalance its capital structure by January 1, 2018, it should file an application explaining why it was unable to do so and the steps that it was taking to get back to a 50/50 capital structure. DP&L has complied with the PUCO's order by filing such an application. For historical segment purposes, up to $750.0 million of long-term debt and the pro rata interest expense associated with that debt has been allocated to the T&D segment. All remaining debt and interest expense has been included in the Generation segment.

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RESULTS OF OPERATIONS HIGHLIGHTS – DP&L



	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2017			2016			2017			2016
Revenues:
Retail	$	164.1		$	197.7		$	488.0		$	554.1
Wholesale	95.0			127.9			283.9			347.2
RTO revenues	14.5			15.2			41.0			43.9
RTO capacity revenues	32.0			27.6			87.9			86.2
Other mark-to-market losses	—			—			—			(0.1		)
Total revenues	305.6			368.4			900.8			1,031.3
Cost of revenues:
Fuel cost:
Fuel	53.1			72.5			153.7			194.4
Gains from the sale of coal	(0.3		)	(1.9		)	(0.9		)	(4.9		)
Mark-to-market losses	—			0.4			—			—
Net fuel cost	52.8			71.0			152.8			189.5
Purchased power:
Purchased power	62.9			85.3			199.3			254.2
RTO charges	16.0			22.7			52.9			59.1
RTO capacity charges	3.4			3.3			9.5			17.4
Mark-to-market losses / (gains)	1.2			(1.3		)	(1.0		)	(2.7		)
Net purchased power cost	83.5			110.0			260.7			328.0
Total cost of revenues	136.3			181.0			413.5			517.5

Gross margin	169.3			187.4			487.3			513.8

Operating expenses:
Operation and maintenance	81.7			85.5			245.2			248.0
Depreciation and amortization	22.7			24.1			68.2			95.2
General taxes	19.6			21.2			66.8			62.8
Gain on termination of contract	—			—			—			(27.7		)
Fixed-asset impairment	—			—			66.3			857.1
Loss / (gain) on asset disposal	(0.3		)	—			15.9			0.2
Other	(4.4		)	—			(4.4		)	—
Total operating expenses	119.3			130.8			458.0			1,235.6

Operating income / (loss)	50.0			56.6			29.3			(721.8		)

Other expense, net
Investment income	0.1			0.1			0.2			0.3
Interest expense	(7.7		)	(6.5		)	(23.1		)	(17.2		)
Charge for early redemption of debt	(1.0		)	(0.5		)	(1.1		)	(0.5		)
Other expense	(0.2		)	0.1			(1.5		)	(0.2		)
Total other expense, net	(8.8		)	(6.8		)	(25.5		)	(17.6		)

Income / (loss) from operations before income tax (a)	$	41.2		$	49.8		$	3.8		$	(739.4	)


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

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DP&L – Revenues

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



	Three months ended			Nine months ended
	September 30,			September 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Retail
Rate	$	(17.0	)	$	(35.3	)
Volume	(15.5		)	(34.2		)
Other miscellaneous	(1.1		)	3.4
Total retail change	(33.6		)	(66.1		)

Wholesale
Rate	(9.4		)	(27.4		)
Volume	(23.5		)	(35.9		)
Total wholesale change	(32.9		)	(63.3		)

RTO revenues and RTO capacity revenues
RTO revenues and RTO capacity revenues	3.7			(1.2		)

Other
Unrealized MTM	—			0.1

Total revenues change	$	(62.8	)	$	(130.5	)

During the three months ended September 30, 2017, Revenues decreased $62.8 million to $305.6 million from $368.4 million in the same period in the prior year. This decrease was primarily the result of the components of revenue discussed below:

Retail revenues decreased $33.6 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, lower rates associated with the competitive bid rider, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as cooling degree days decreased by 290 degree days. The aforementioned impacts resulted in an unfavorable $17.0 million retail price variance and an unfavorable $15.5 million retail volume variance. In addition, there was an unfavorable other miscellaneous variance of $1.1 million.

Wholesale revenues decreased $32.9 million primarily as a result of an unfavorable $23.5 million wholesale volume variance and an unfavorable $9.4 million wholesale price variance. The unfavorable price variance was due to lower PJM market prices in the third quarter of 2017 and lower realized gains on derivatives. The decrease in wholesale volumes of $23.5 million was primarily driven by a decrease in the load served of other parties through their competitive bid process, as well as a 19% decrease in internal generation at DP&L's plants in 2017.

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RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and PJM capacity payments, increased $3.7 million compared to the same period in the prior year. This increase was the result of a $4.4 million increase in revenue realized from the PJM capacity auction in 2017 due to higher prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016. This increase was partially offset by a $0.7 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves.

During the nine months ended September 30, 2017, Revenues decreased $130.5 million to $900.8 million from $1,031.3 million in the same period in the prior year. This decrease was primarily the result of the components of revenue discussed below:

Retail revenues decreased $66.1 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, collections on the remaining 2015 deferred fuel balance in the first quarter of 2016, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree days decreased by 449 degree days and cooling degree days decreased by 313 degree days. The aforementioned impacts resulted in an unfavorable $35.3 million retail price variance and an unfavorable $34.2 million retail volume variance. These variances were partially offset by a favorable other miscellaneous variance of $3.4 million.

Wholesale revenues decreased $63.3 million primarily as a result of an unfavorable $35.9 million wholesale volume variance and an unfavorable $27.4 million wholesale price variance. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes of $35.9 million was primarily driven by a decrease in the load served of other parties through their competitive bid process and an 8% decrease in internal generation at DP&L's plants in 2017.

RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and PJM capacity payments, decreased $1.2 million compared to the same period in the prior year. This decrease was the result of a $2.9 million decrease in RTO revenues due to lower rates and availability related to compensation for DP&L's reactive supply and operating reserves. This decrease was partially offset by a $1.7 million increase in revenue realized from the PJM capacity auction in 2017 primarily due to higher average prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016, and $136/MW-day in June of 2015.

DP&L – Cost of Revenues

During the three months ended September 30, 2017, Cost of revenues decreased $44.7 million compared to the same period in the prior year:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $18.2 million, compared to the same period in the prior year primarily due to a 10% decrease in average fuel cost per MWh and a 19% decrease in internal generation at DP&L's plants in 2017.

Net purchased power decreased $26.5 million compared to the prior year. This decrease was driven by the following factors:

◦

Purchased power decreased $22.4 million primarily due to a $12.2 million volume decrease and a $10.2 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 than 2016 and lower PJM market rates.

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◦

RTO charges decreased $6.7 million compared to the same period in the prior year due to lower transmission and congestion charges. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within our network, which are incurred and charged to customers in the transmission rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.


◦	RTO capacity charges increased $0.1 million compared to the same period in the prior year primarily due to increases in RTO capacity prices. As noted above, RTO capacity prices are set by an annual auction. The increase in RTO capacity prices was partially offset by a lower retail load served in 2017. Retail load served relates to the load of other parties through their competitive bid process.


◦	Mark-to-market losses increased $2.5 million compared to the same period in the prior year due to changes in power prices in 2017 and 2016.

During the nine months ended September 30, 2017, Cost of revenues decreased $104.0 million compared to the same period in the prior year:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $36.7 million, compared to the same period in the prior year primarily due to a 14% decrease in average fuel cost per MWh and an 8% decrease in internal generation. There were fuel costs deferred in 2015, which were expensed in 2016 because they were collected in 2016, which contributed to the price decrease. There were no fuel costs deferred or collected in 2017.

Net purchased power decreased $67.3 million compared to the prior year. This decrease was driven by the following factors:

◦

Purchased power decreased $54.9 million primarily due to a $35.0 million volume decrease and a $19.9 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 than 2016.

◦

RTO charges decreased $6.2 million compared to the same period in the prior year due to lower transmission and congestion charges. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within our network, which are incurred and charged to customers in the transmission rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.

◦

RTO capacity charges decreased $7.9 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted above, RTO capacity prices are set by an annual auction.


◦	Mark-to-market gains decreased $1.7 million compared to the same period in the prior year due to changes in power prices in 2017 and 2016.

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DP&L – Operation and Maintenance

During the three and nine months ended September 30, 2017, Operation and Maintenance expense decreased $3.8 million and $2.8 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:



	Three months ended			Nine months ended
	September 30,			September 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)	$	(6.3	)	$	(18.4	)
Decrease in generating facilities operating and maintenance expenses	(3.6		)	(2.3		)
Increase in retirement benefits costs, primarily due to pension curtailment charges associated with announced plant closures in the first quarter of 2017	0.7			7.6
Increase in group insurance expense associated with participation in the AES self-insurance plan	—			7.2
Insurance recoveries from MVIC in 2016	2.9			2.9
Increase in legal and other consulting costs	1.2			2.8
Other, net	1.3			(2.6		)
Net change in operation and maintenance expense	$	(3.8	)	$	(2.8	)


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

DP&L – Depreciation and Amortization

During the three months ended September 30, 2017, Depreciation and amortization decreased $1.4 million, compared to the same period in the prior year. The decrease was primarily the result of the fixed-asset impairments in the fourth quarter of 2016 and the first quarter of 2017, which reduced depreciation expense due to lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fort and Zimmer depreciation expense due to the pending sale of these two plants.

During the nine months ended September 30, 2017, Depreciation and amortization decreased $27.0 million, compared to the same period in the prior year. The decrease was primarily a result of the fixed-asset impairments in the second and fourth quarters of 2016 and the first quarter of 2017, which reduced depreciation expense due to the lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fort and Zimmer depreciation expense due to the pending sale of these two plants.

DP&L – General Taxes

During the three months ended September 30, 2017, General taxes decreased $1.6 million compared to the same period in the prior year. The decrease was primarily the result of a true-up of the 2017 Ohio property tax accrual to reflect final assessments for 2017 taxes.

During the nine months ended September 30, 2017, General taxes increased $4.0 million compared to the same period in the prior year. The increase was primarily the result of lower Ohio property tax expense in 2016 due to a $1.6 million favorable true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016 and a 2017 unfavorable true-up of $1.2 million for the 2016 Ohio property tax accrual to reflect actual payments made in 2017, as well as higher Ohio property tax rates in 2017.

DP&L – Gain on Termination of Contract

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

DP&L – Fixed-asset Impairment

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

During the nine months ended September 30, 2016, DP&L recorded an impairment of fixed assets of $857.1 million. A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue

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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 Killen and certain DP&L peaking generating facilities were not recoverable. For more information, see Note 14 – Fixed-asset Impairments of Notes to DP&L's Condensed Financial Statements.

DP&L – Loss / (gain) on asset disposal

During the nine months ended September 30, 2017, DP&L recorded a loss on asset disposal of $15.9 million primarily related to the write-off of plant materials and supplies inventory at the Stuart and Killen plants.

DP&L – Other

During the three and nine months ended September 30, 2017, Other operating expenses were reduced by $4.4 million primarily due to insurance recoveries recorded in 2017.

DP&L – Interest Expense

During the three months ended September 30, 2017, Interest expense increased $1.2 million compared to the same period in the prior year primarily due to higher interest rates on the $445.0 million variable rate Term Loan B maturing on August 24, 2022 compared to the interest rate on the 1.875% First Mortgage Bonds Due 2016.

During the nine months ended September 30, 2017, Interest expense increased $5.9 million compared to the same period in the prior year primarily due to higher interest rates on the $445.0 million variable rate Term Loan B maturing on August 24, 2022 compared to the interest rate on the 1.875% First Mortgage Bonds Due 2016.

DP&L – Income Tax Expense

During the three months ended September 30, 2017, Income tax expense decreased $7.8 million compared to the same period in the prior year primarily due to a lower annualized effective tax rate and lower pretax income in the current year versus the prior year.

During the nine months ended September 30, 2017, Income tax expense / (benefit) decreased $271.8 million compared to the same period in the prior year primarily due to a significantly large pre-tax loss in the prior year versus pre-tax income in the current year.

RESULTS OF OPERATIONS BY SEGMENT – DP&L

Through September 30, 2017, DP&L managed the business through two reportable operating segments, the T&D segment and the Generation segment. After Generation Separation, DP&L will have only one reportable operating segment, the T&D segment, beginning on October 1, 2017. The primary segment performance measure is income / (loss) from operations before income tax as management has concluded that this measure best reflects the underlying business performance of DP&L and is the most relevant measure considered in DP&L’s internal evaluation of the financial performance of its segments. The segments are discussed further below:

Transmission and Distribution Segment

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

Generation Segment

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

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

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



	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2017		2016		2017			2016
T&D	$	20.0	$	36.5	$	60.1		$	98.5
Generation	21.2		13.3		(56.3		)	(837.9		)
Income / (loss) from operations before income tax (a)	$	41.2	$	49.8	$	3.8		$	(739.4	)


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

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Statement of Operations Highlights – DP&L – Generation Segment



	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2017			2016			2017			2016
Revenues:
Retail	$	0.1		$	0.1		$	0.2		$	0.2
Wholesale	89.1			122.6			269.4			334.9
RTO revenues	2.0			3.7			5.5			9.7
RTO capacity revenues	30.2			26.2			83.2			81.2
Other mark-to-market losses	—			—			—			(0.1		)
Total revenues	121.4			152.6			358.3			425.9
Cost of revenues:
Cost of fuel:
Fuel	53.1			72.5			153.7			188.8
Gains from the sale of coal	(0.3		)	(1.9		)	(0.9		)	(4.6		)
Mark-to-market losses	—			0.4			—			—
Net fuel cost	52.8			71.0			152.8			184.2
Purchased power:
Purchased power	4.7			11.4			21.1			54.3
RTO charges	0.3			7.0			9.7			14.8
RTO capacity charges	2.9			3.1			8.9			17.6
Mark-to-market losses / (gains)	1.2			(1.3		)	(1.0		)	(2.7		)
Net purchased power cost	9.1			20.2			38.7			84.0
Total cost of revenues	61.9			91.2			191.5			268.2

Gross margin	59.5			61.4			166.8			157.7

Operating expenses:
Operation and maintenance	39.3			38.2			123.8			113.1
Depreciation and amortization	3.1			6.3			11.9			40.1
General taxes	0.3			3.5			9.0			12.1
Gain on termination of contract	—			—			—			(27.7		)
Fixed-asset impairment	—			—			66.3			857.1
Loss on asset disposal	—			—			16.2			0.6
Other	(4.4		)	—			(4.4		)	—
Total operating expenses	38.3			48.0			222.8			995.3

Other income / (expense), net	21.2			13.4			(56.0		)	(837.6		)

Other expense, net
Interest expense	—			(0.1		)	(0.2		)	(0.3		)
Other expense	—			—			(0.1		)	—
Total other expense, net	—			(0.1		)	(0.3		)	(0.3		)

Income / (loss) from operations before income tax (a)	$	21.2		$	13.3		$	(56.3	)	$	(837.9	)


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

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DP&L –Generation Segment – Revenues

During the three months ended September 30, 2017, the segment’s revenues decreased $31.2 million to $121.4 million from $152.6 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes and lower average wholesale rates, partially offset by higher RTO capacity and other revenues.

Wholesale revenues decreased $33.5 million primarily as a result of an unfavorable wholesale volume variance of $29.2 million and an unfavorable wholesale price variance of $4.3 million. The unfavorable price variance was due to lower PJM market prices in the third quarter of 2017 and lower realized gains on derivatives. The decrease in wholesale volumes was primarily driven by a decrease in the load served of other parties through their competitive bid process, as well as a 19% decrease in internal generation at DP&L's plants in 2017.

RTO capacity and other revenues increased $2.3 million compared to the same period in the prior year. This increase was the result of a $4.0 million increase in revenue realized from the PJM capacity auction in 2017 due to higher prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016. This increase was partially offset by a $1.7 million decrease in RTO revenues due to lower rates and availability related to compensation for DP&L's reactive supply and operating reserves.

During the nine months ended September 30, 2017, the segment’s revenues decreased $67.6 million to $358.3 million from $425.9 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes, lower average wholesale rates, and lower RTO capacity and other revenues.

Wholesale revenues decreased $65.5 million primarily as a result of an unfavorable wholesale volume variance of $41.6 million and an unfavorable wholesale price variance of $23.9 million. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes was primarily driven by a decrease in the load served of other parties through their competitive bid process and an 8% decrease in internal generation at DP&L's plants in 2017.

RTO capacity and other revenues, consisting primarily of PJM capacity payments, decreased $2.2 million compared to the same period in the prior year primarily due to a $4.2 million decrease in RTO revenues due to lower rates and availability related to compensation for DP&L's reactive supply and operating reserves. This decrease was partially offset by a $2.0 million increase in revenue realized from the PJM capacity auction in 2017 primarily due to higher average prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016, and $136/MW-day in June of 2015.

DP&L –Generation Segment – Cost of Revenues

During the three months ended September 30, 2017, Total cost of revenues decreased $29.3 million compared to the prior year. This decrease was a result of:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $18.2 million compared to the same period in the prior year primarily due to a 10% decrease in average fuel cost per MWh and a 19% decrease in internal generation at DP&L's plants in 2017.

Net purchased power decreased $11.1 million compared to the prior year. This decrease was driven by the following factors:

◦

Purchased power decreased $6.7 million primarily due to a favorable volume variance of $4.5 million and a favorable price variance of $2.2 million. The decrease in volume was driven by a lower load served of other parties through their competitive bid process in 2017. The price decrease was primarily driven by lower PJM market rates in the third quarter of 2017. The generation segment purchases power to source retail load in other service territories and to meet contracted Wholesale requirements when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.


◦	RTO charges decreased $6.7 million compared to the same period in the prior year primarily due to lower transmission and congestion charges.

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◦	RTO capacity charges decreased $0.2 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, partially offset by higher RTO capacity prices. Retail load served relates to the load of other parties through their competitive bid process.


◦	Mark-to-market losses increased $2.5 million due to changes in power prices in 2017 and 2016.

During the nine months ended September 30, 2017, Total cost of revenues decreased $76.7 million compared to the prior year. This decrease was a result of:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $31.4 million compared to the same period in the prior year primarily due to a 14% decrease in average fuel cost per MWh and an 8% decrease in internal generation at DP&L's plants in 2017.

Net purchased power decreased $45.3 million compared to the prior year. This decrease was driven by the following factors:

◦

Purchased power decreased $33.2 million primarily due to a favorable volume variance of $29.9 million and a favorable price variance of $3.3 million. The decrease in volume was driven by a lower load served of other parties through their competitive bid process in 2017. The generation segment purchases power to source retail load in other service territories and to meet contracted Wholesale requirements when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.


◦	RTO charges decreased $5.1 million compared to the same period in the prior year primarily due to lower transmission and congestion charges.

◦

RTO capacity charges decreased $8.7 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted above, RTO capacity prices are set by an annual auction.


◦	Mark-to-market gains decreased $1.7 million due to changes in power prices in 2017 and 2016.

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DP&L –Generation Segment – Operating Expenses

During the three and six months ended June 30, 2017, Operating expenses decreased $9.7 million and $772.5 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:



	Three months ended			Nine months ended
	September 30,			September 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Change in Fixed-asset impairment from 2016 to 2017 ^(a)	$	—		$	(790.8	)
Decrease in Depreciation and amortization expense as a result of the fixed-asset impairments in the second and fourth quarters of 2016 and the first quarter of 2017, which reduced depreciation expense due to the lower asset values	(3.2		)	(28.2		)
Higher insurance recoveries in 2017	(4.4		)	(4.4		)
Decrease in General taxes due to a true-up of the year to date 2017 Ohio property tax accrual for generation to reflect final assessments for 2017 taxes recorded in the third quarter of 2017	(3.2		)	(3.1		)
Decrease in generating facilities operating and maintenance expenses	(2.6		)	(1.0		)
Gain on termination of contract in 2016	—			27.7
Loss on asset disposal ^(b)	—			15.6
Increase / (decrease) in retirement benefits costs, primarily due to pension curtailment charges associated with announced plant closures in the first quarter	(0.1		)	5.7
Increase in group insurance expense associated with participation in the AES self-insurance plan	—			3.8
Other, net	3.8			2.2
Net change in operating expenses	$	(9.7	)	$	(772.5	)

(a)

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


(b)	During the nine months ended September 30, 2017, the Generation segment recorded a loss on asset disposal of $16.2 million primarily related to the write-off of plant materials and supplies inventory at the Stuart and Killen plants.

DP&L –Generation Segment – Interest Expense

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

KEY TRENDS AND UNCERTAINTIES

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

PJM capacity prices;

Effect of implementing DP&L's ESP 3 order approved on October 20, 2017 with rates to be effective November 1, 2017;

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

Operational performance of generation facilities;

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

Sale or transfer of generation assets now owned by AES Ohio Generation; and

DPL's ability to reduce its cost structure.

Operational

On March 17, 2017, the Board of Directors of DP&L approved the retirement of the DP&L operated and co-owned Stuart Station coal-fired and diesel-fired generating units and the DP&L operated and co-owned Killen Station coal-fired generating unit and combustion turbine on or before June 1, 2018, and the co-owners of these facilities agreed with DP&L to proceed with this plan of retirement. In the first quarter of 2017, DPL incurred an impairment charge of $66.4 million and DP&L incurred an impairment charge of $66.3 million related to these planned retirements. See Note 14 – Fixed-asset Impairments of Notes to DPL's Condensed Consolidated Financial Statements and Note 14 – Fixed-asset Impairments of Notes to DP&L's Condensed Financial Statements for more information. DPL and DP&L also recorded pension curtailment charges of $4.1 million and $5.6 million, respectively, and inventory write off charges of $16.2 million in the first quarter of 2017 associated with the planned retirement.

In addition to the charges noted above, DPL and DP&L estimate that they will incur $7.0 million to $13.0 million in severance and benefit related costs during 2017 and 2018 and approximately $10.0 million to $30.0 million in plant shutdown costs, the timing of which is uncertain as of the date of this report. In addition, DPL also estimates future cash expenditures of approximately $130.0 million for asset retirement obligations beginning in June 2018 and through 2023.

On October 1, 2017, Stuart Unit 1 was retired due to damage sustained when a high-pressure feedwater heater shell failed on January 10, 2017.

In addition to our plans to exit coal capacity, we are pursuing the sale of our peaker generation assets. We expect to announce a transaction by year-end with closing expected in the first half of 2018.

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

Regulatory Environment

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

In January 2017, DP&L filed a settlement in its ESP 3 case and filed an amended stipulation on March 13, 2017, which was subject to approval by the PUCO. A final decision was issued by the PUCO on October 20, 2017, modifying and adopting the amended stipulation and recommendation. The ESP establishes DP&L's framework for providing retail service on a going forward basis including rate structures, non-bypassable charges and other specific rate recovery true-up mechanisms. The signatory parties agreed to a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:

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

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

The establishment of a non-bypassable Distribution Investment Rider to recover incremental distribution capital investments, the amount of which is to be established in a separate DP&L distribution rate case

A non-bypassable Reconciliation Rider permitting DP&L to defer, recover or credit the net proceeds from selling energy and capacity received as part of DP&L’s investment in OVEC and DP&L's OVEC related costs;

Implementation by DP&L of a Smart Grid Rider, Economic Development Rider, Economic Development Fund, Regulatory Compliance Rider and certain other new, or changes to existing, rates, riders and

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competitive retail market enhancements, with tariffs consistent with the order to be effective November 1, 2017;

Restrictions on DPL making dividend or tax sharing payments; and

Various other riders and competitive retail market enhancements.

DP&L’s ESP 2 had been approved by the PUCO for the years 2014 - 2016, and permitted DP&L to collect a non-bypassable service stability rider equal to $110.0 million per year for each of those years and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. The Ohio Supreme Court in a June 2016 opinion stated that the PUCO’s approval of the ESP was reversed. In view of that reversal, DP&L filed a motion to withdraw its ESP 2 and implement rates consistent with those in effect prior to 2014. The PUCO approved DP&L’s withdrawal of ESP 2 and implementation plans. Those rates were in effect until rates approved as a result of DP&L’s pending ESP 3 are effective, November 1, 2017. In February 2017, several parties appealed the PUCO orders that approved both the withdrawal and the implementation plans to the Ohio Supreme Court. Those appeals are pending, and the outcome and potential financial impact of those appeals cannot be determined at this time. In July 2017, the Office of the Ohio Consumers Counsel filed a motion with the Ohio Supreme Court seeking to stay collection of the reinstated prior rates while the appeals are pending. That stay was denied by the Ohio Supreme Court in September 2017.

The Department of Energy (DOE) issued a Notice of Proposed Rule Making (NOPR) on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. Nuclear and coal-fired generation plants are most likely to be able to meet the requirements. As proposed, the DOE would value resiliency through rates that recover “compensable costs” that are defined to include the recovery of operating and fuel expenses, debt service and a fair return on equity. The FERC is proceeding on an expedited basis, as requested by the DOE, but the timing and outcome of the proposed rule, including effects on wholesale energy markets, remains uncertain.

Environmental

We refer to the discussion in “Item 1. Business - Environmental Matters - Climate Change Legislation and Regulation” in our 2016 Form 10-K for a discussion of certain recent developments in environmental laws and regulations, including the USEPA’s CO2 emissions rules for new electric generating units, or GHG NSPS, as well as the CO2 emissions rules for existing power plants, called the CPP. Both the GHG NSPS and the CPP are being challenged by several states and industry groups in the D.C. Circuit Court. The challenges to the CPP have been fully briefed and argued but oral arguments have not yet taken place on the GHG NSPS. Challenges to both rules are currently being held in abeyance. Additionally, by order of the U.S. Supreme Court, the CPP has been stayed pending resolution of the challenges to the rule. On October 16, 2017, the USEPA published a proposed rule to repeal the CPP in its entirety on the legal basis that the rule exceeds the USEPA’s statutory authority. The USEPA will accept comments on the proposal until December 15, 2017.

Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form, could be material. The GHG NSPS remains in effect at this time, and, absent further action from the USEPA that rescinds or substantively revises the NSPS, it could impact our plans to construct and/or modify or reconstruct electric generating units in some locations, which may have a material impact on our business, financial condition or results of operations.

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In response to Executive Orders, USEPA is currently evaluating various existing regulations to be considered for repeal, replacement, or modification. We cannot predict at this time the likely outcome of the USEPA’s review of other existing regulations or what impact it may have on our business.

On September 27, 2017, the State of Maryland filed a complaint against the USEPA for failing to address its

November 2016 CAA petition to the USEPA to determine that 36 electric generating units in five upwind states, including DP&L's Killen unit, emit pollutants that contribute to non-attainment of NAAQS for Ozone in Maryland, as described further in our 2016 Form 10-K. If this petition is granted or the suit is decided favorably to the Maryland Department of the Environment, certain of our facilities could be subject to additional requirements. In light of the scheduled retirement of the Killen unit, we do not expect any additional requirements to have a material impact on us.

The USEPA's final CCR rule became effective on October 19, 2015. Generally, the rule regulates CCR as nonhazardous solid waste and establishes national minimum criteria for existing and new CCR landfills and existing and new CCR surface impoundments (ash ponds), including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements and post-closure care. On September 13, 2017, the USEPA indicated that it would reconsider certain provisions of the CCR rule in response to two petitions it received to reconsider the final rule. It is too early to determine whether this may have a material impact on our business, financial condition or results of operations.

CAPITAL RESOURCES AND LIQUIDITY

DPL and DP&L had cash and cash equivalents of $23.4 million and $15.3 million, respectively, at September 30, 2017. At that date, neither DPL nor DP&L had short-term investments. DPL and DP&L had aggregate principal amounts of long-term debt outstanding of $1,761.5 million and $659.6 million, respectively.

Approximately $29.7 million of DPL's long-term debt including $4.7 million of DP&L's long-term debt matures within the next twelve months, which we expect to repay using a combination of cash on hand, net cash provided by operating activities and/or net proceeds from the issuance of new debt. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions or otherwise when management believes such repurchases are favorable to make. The amounts involved in any such repurchases may be material.

We depend on timely and continued access to capital markets to manage our liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on our financial condition and results of operations. In addition, changes in the timing of tariff increases or delays in regulatory determinations could affect the cash flows and results of operations of our businesses.

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

CASH FLOWS - DPL

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



DPL	Nine months ended September 30,
$ in millions	2017			2016
Net cash provided by operating activities	$	81.7		$	198.6
Net cash used in investing activities	(55.8		)	(23.1		)
Net cash used in financing activities	(57.1		)	(86.1		)

Net change	(31.2		)	89.4
Balance at beginning of period	54.6			32.4
Cash and cash equivalents at end of period	$	23.4		$	121.8

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DPL - Change in cash flows from operating activities



	Nine months ended September 30,						$ change
$ in millions	2017			2016			2017 vs. 2016
Net income / (loss)	$	(29.3	)	$	(89.9	)	$	60.6
Depreciation and amortization	81.8			100.3			(18.5		)
Impairment expenses	66.4			235.5			(169.1		)
Gain on sale of business	—			(49.2		)	49.2
Deferred income taxes	(3.5		)	(101.4		)	97.9
Other adjustments to Net income / (loss)	19.2			3.2			16.0
Net income / (loss), adjusted for non-cash items	134.6			98.5			36.1
Net change in operating assets and liabilities	(52.9		)	100.1			(153.0		)
Net cash provided by operating activities	$	81.7		$	198.6		$	(116.9	)

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



$ in millions	$ Change
Decrease from accrued taxes payable primarily due to an income tax benefit from the current year loss	$	(59.3	)
Decrease from accounts receivable due to lower collections	(7.8		)
Decrease from accounts payable due to timing of payments	(36.2		)
Decrease from deferred regulatory costs, net, due to lower collections on regulatory assets and liabilities	(26.0		)
Decrease from inventory primarily due to lower coal purchases in 2016	(19.6		)
Other	(4.1		)
Total decrease in cash from changes in operating assets and liabilities	$	(153.0	)

DPL - Cash flows from investing activities

Capital expenditures, primarily related to transmission and distribution, continue to be our principal use of cash related to investing activities. Net cash from investing activities was $(55.8) million for the nine months ended September 30, 2017 compared to $(23.1) million for the nine months ended September 30, 2016, primarily driven by a decrease in proceeds from sale of business of $75.5 million, related to the sale of DPLER in January 2016, which was partially offset by a favorable change in restricted cash of $21.5 million, related to a decrease in collateral requirements on derivatives, lower capital expenditures of $14.2 million, and $7.4 million higher insurance proceeds received.

DPL - Cash flows from financing activities

Net cash used in financing activities was $(57.1) million for thenine months ended September 30, 2017 compared to $(86.1) million from financing activities for the nine months ended September 30, 2016. For thenine months ended September 30, 2017, this was primarily due to $122.1 million of payments on long-term debt from the redemption of the $100.0 million 4.8% first mortgage bonds and quarterly payments on the DPL and DP&L term loans, partially offset by $65.0 million net draws on revolving credit facilities. During the nine months ended September 30, 2016, we redeemed $73.0 million of DPL's $130.0 million 6.5% Senior Unsecured Notes Due 2016, along with the related make-whole premium payment of $2.4 million and deferred financing cost payments of $8.0 million.

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CASH FLOWS - DP&L

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



DP&L	Nine months ended September 30,
$ in millions	2017			2016
Net cash provided by operating activities	$	98.7		$	220.4
Net cash used in investing activities	(42.7		)	(86.6		)
Net cash used in financing activities	(42.3		)	(46.3		)

Net change	13.7			87.5
Balance at beginning of period	1.6			5.4
Cash and cash equivalents at end of period	$	15.3		$	92.9

DP&L - Change in cash flows from operating activities



	Nine months ended September 30,						$ change
$ in millions	2017			2016			2017 vs. 2016
Net income / (loss)	$	3.6		$	(467.8	)	$	471.4
Depreciation and amortization	68.2			95.2			(27.0		)
Impairment expenses	66.3			857.1			(790.8		)
Deferred income taxes	1.6			(314.2		)	315.8
Other adjustments to Net income / (loss)	17.0			0.7			16.3
Net income / (loss), adjusted for non-cash items	156.7			171.0			(14.3		)
Net change in operating assets and liabilities	(58.0		)	49.4			(107.4		)
Net cash provided by operating activities	$	98.7		$	220.4		$	(121.7	)

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



$ in millions	$ Change
Decrease from accrued taxes payable, due to income tax benefit incurred on current year loss	$	(40.7	)
Decrease from accounts payable due to timing of payments	(44.9		)
Decrease from deferred regulatory costs, net, due to lower collections on regulatory assets and liabilities	(26.0		)
Decrease from inventory primarily due to lower coal purchases in 2016	(19.4		)
Increase from accounts receivable due to higher collections	31.5
Other	(7.9		)
Total decrease in cash from changes in operating assets and liabilities	$	(107.4	)

DP&L - Cash flows from investing activities

Net cash from investing activities was $(42.7) million for thenine months ended September 30, 2017 compared to $(86.6) million for the nine months ended September 30, 2016, primarily due to a $21.5 million favorable change in restricted cash, due to a change in the collateral requirements on derivatives, and lower capital expenditures of $15.9 million.

DP&L - Cash flows from financing activities

Net cash used in financing activities was $(42.3) million for the nine months ended September 30, 2017 compared to $(46.3) million from financing activities for the nine months ended September 30, 2016. For the nine months ended September 30, 2017, this was due to the redemption of the $100.0 million 4.8% first mortgage bonds and repayments on the DP&L term loan and dividends and returns of capital paid to parent of $19.0 million, partially offset by a $70.0 million capital contribution from DPL. During the nine months ended September 30, 2016, DP&L had net repayments of $35.0 million of short-term debt to its parent, DPL, and $8.0 million payments of deferred financing costs.

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LIQUIDITY

We expect our existing sources of liquidity to remain sufficient to meet our anticipated operating needs. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to energy hedges and dividend payments. In 2017 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from debt financing as internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under bank credit facilities will continue to be available to us to manage working capital requirements during these periods.

At September 30, 2017, DP&L and DPL have access to the following revolving credit facilities:



$ in millions	Type	Maturity	Commitment		Amounts available as of September 30, 2017
DP&L	Revolving	July 2020	$	175.0	$	158.6
DPL	Revolving	July 2020	205.0		142.1
			$	380.0	$	300.7

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 September 30, 2017, there were two letters of credit in the aggregate amount of $1.4 million outstanding under this facility, and $15.0 million borrowed on the facility, 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, 2017 or 2016.

DPL has a revolving credit facility of $205.0 million, with a $200.0 million letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility by an additional $95.0 million. This facility is secured by a pledge of common stock that DPL owns in DP&L, limited to the amount permitted to be pledged under certain Indentures dated October 3, 2011 and October 6, 2014 between DPL and Wells Fargo Bank, NA and U.S. Bank National Association, respectively, as Trustee and a limited recourse guarantee by AES Ohio Generation secured by assets of AES Ohio Generation. DPL further secured the credit facility through a leasehold mortgage on additional assets of AES Ohio Generation. The facility expires in July 2020; however, DPL's credit facility has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019. At September 30, 2017, there were five letters of credit in the aggregate amount of $12.9 million outstanding under this facility, and $50.0 million borrowed on the facility, with the remaining $142.1 million available to DPL. Fees associated with this facility were not material during the nine months ended September 30, 2017 or 2016.

Capital Requirements

Planned construction additions for 2017 relate primarily to new investments in and upgrades to DP&L’s power plant equipment and transmission and distribution system. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental requirements, among other factors.

DPL is projecting to spend an estimated $358.0 million in capital projects for the period 2017 through 2019, of which $297.0 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 $11.3 million within the next five years to reinforce its 138 kV system to comply with NERC standards. Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds and the reasonable cost of external funds. We expect to finance our construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.

Long-term debt covenants

The DPL revolving credit facility and the DPL term loan agreement have a Total Debt to EBITDA covenant that will be calculated, at the end of each fiscal quarter, by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The ratio in the agreements is not to exceed 7.25 to 1.00 for any fiscal quarter ending September 30, 2015 through December 31, 2018; it then steps down not to exceed 6.25

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to 1.00 for any fiscal quarter ending March 31, 2019 through December 31, 2019; and it then steps down not to exceed 5.75 to 1.00 for any fiscal quarter ending March 31, 2020 through July 31, 2020. As of September 30, 2017, the financial covenant was met with a ratio of 6.76 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, 2017, this financial covenant was met with a ratio of 2.46 to 1.00.

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

The DP&L revolving credit facility and Bond Purchase and Covenants Agreement also have an EBITDA to Interest Expense financial covenant that is calculated at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the interest charges for the same period. Both prior to and after completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s EBITDA to Interest Expense cannot be less than 2.50 to 1.00. As of September 30, 2017, this covenant was met with a ratio of 7.61 to 1.00.

Debt and Credit Ratings

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



	DPL	DP&L	Outlook	Effective or Affirmed
Fitch Ratings	BBB-^(a) / BB+^(b)	BBB+^(c)	Positive	October 2017
Moody's Investors Service, Inc.	Ba3^(b)	Baa2^(c)	Positive	October 2017
Standard & Poor's Financial Services LLC	BB-^(b)	BBB-^(c)	Stable	October 2017


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


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


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

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



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

Off-Balance Sheet Arrangements

For information on guarantees, commercial commitments, and contractual obligations, see Note 10 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DPL’s Condensed Consolidated Financial Statements and Note 11 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DP&L’s Condensed Financial Statements.

MARKET RISK

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 monthly through the Statement of Operations or, where applicable, we recognize a corresponding Regulatory asset for above-market costs or a Regulatory liability for below-market costs in accordance with regulatory accounting under GAAP.

The coal market has increasingly been influenced by both international and domestic supply and consumption, making the price of coal more volatile than in the past, and while we have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2017 under contract; sales requirements may change. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled outages and generation plant mix.

Commodity Derivatives

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

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

At September 30, 2017, a 10% increase or decrease in the market price of our net forward power contracts and net natural gas contracts would result in a net impact on unrealized gains/losses of $(0.6) million and $0.7 million, respectively.

Wholesale Revenues

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



DPL	Nine months ended
	September 30,
	2017		2016
Percent of electric revenues from wholesale market	32	%	34	%

DP&L	Nine months ended
	September 30,
	2017		2016
Percent of electric revenues from wholesale market	32	%	34	%

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

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



$ in millions	DPL		DP&L
Effect of 10% change in price per MWh	$	26.6	$	25.4

Capacity Revenues and Costs

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



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

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



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

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

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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, 2017 of a hypothetical increase or decrease of $10/MW-day in the RPM auction price. The table shows the impact resulting from capacity revenue changes. We did not include the impact of a change in the RPM capacity costs since these costs will be recovered through the development of our overall energy pricing for customers.



$ in millions	DPL		DP&L
Effect of $10/MW-day change in capacity auction pricing	$	5.7	$	4.8

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 ended September 30, 2017 were 40% and 41%, respectively. We have a significant portion of projected 2017 fuel needs under contract. Most of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We may purchase SO₂ allowances for 2017, however, the exact consumption of SO₂ allowances will depend on market prices for power, availability of our generation units and the actual sulfur content of the coal burned. We may purchase some NOx allowances for 2017 depending on NOx emissions. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and generation plant mix.

We purchase power for our SSO load sourced through the competitive bid process and to serve the load of other parties through their competitive bid process. 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, 2017 of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power:



$ in millions	DPL		DP&L
Effect of 10% change in fuel and purchased power	$	18.9	$	17.5

Interest Rate Risk

Because of our normal investing and borrowing activities, our financial results are exposed to fluctuations in interest rates which we manage through our regular financing activities. We maintain both cash on deposit and investments in cash equivalents that may be affected by adverse interest rate fluctuations. DPL and DP&L have both fixed-rate and variable-rate long-term debt. DPL’s variable-rate debt consists of a $106.3 million term loan with a syndicated bank group. The term loan interest rate fluctuates with changes in an underlying interest rate index, typically LIBOR. DP&L’s variable-rate debt is comprised of bank held tax exempt bonds and a variable rate term loan B. The variable-rate bonds and term loan B bear interest based on an underlying interest rate index, typically LIBOR. Market indexes can be affected by market demand, supply, market interest rates and other economic conditions. See Note 7 – Long-term Debt of Notes to DPL’s Condensed Consolidated Financial Statements and Note 7 – Long-term Debt of Notes to DP&L’s Condensed Financial Statements.

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portfolio-level for reasonableness versus comparable published rates. We reclassify gains and losses on the swaps out of AOCI and into earnings in those periods in which hedged interest payments occur.

Principal Payments and Interest Rate Detail by Contractual Maturity Date

The principal value of DPL’s long-term debt was $1,761.5 million at September 30, 2017, consisting of DPL’s unsecured notes and unsecured term loan, along with DP&L’s first mortgage bonds, tax-exempt bonds and the Wright-Patterson Air Force Base note. All of DPL’s long-term debt was adjusted to fair value at the date of the Merger. The fair value of this long-term debt at September 30, 2017 was $1,843.8 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DPL’s long-term debt obligations that are sensitive to interest rate changes:



DPL
	Principal payments due												At September 30, 2017
	during the twelve months ending												At September 30, 2017
	September 30,												Principal		Fair
$ in millions	2018		2019		2020		2021		2022		Thereafter		Amount		Value
Long-term debt ^(a)
Variable-rate debt	$	29.5	$	29.5	$	60.8	$	4.5	$	423.7	$	—	$	548.0	$	548.0
Average interest rate ^(b)	4.1%		4.1%		4.0%		4.5%		4.5%		—%
Fixed-rate debt ^(c)	$	0.1	$	0.2	$	400.2	$	0.2	$	780.2	$	32.6	1,213.5		1,295.8
Average interest rate	4.2%		4.2%		4.3%		4.2%		7.2%		6.1%
Total													$	1,761.5	$	1,843.8


(a)	Amounts exclude immaterial capital lease obligations


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


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

The principal value of DP&L’s long-term debt was $659.6 million at September 30, 2017, consisting of its first mortgage bonds, tax-exempt bonds and the Wright-Patterson Air Force Base note. The fair value of this long-term debt was $659.5 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, 2017
	during the twelve months ending												At September 30, 2017
	September 30,												Principal		Fair
$ in millions	2018		2019		2020		2021		2022		Thereafter		Amount		Value
Long-term debt ^(a)
Variable-rate debt	$	4.5	$	4.5	$	4.5	$	4.5	$	423.7	$	—	$	441.7	$	441.7
Average interest rate ^(b)	4.5%		4.5%		4.5%		4.5%		4.5%		—%
Fixed-rate debt ^(c)	$	0.1	$	0.2	$	200.2	$	0.2	$	0.2	$	17.0	217.9		217.8
Average interest rate	4.2%		4.2%		1.8%		4.2%		4.2%		4.2%
Total													$	659.6	$	659.5


(a)	Amounts exclude immaterial capital lease obligations


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


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

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

Long-term Debt Interest Rate Risk Sensitivity Analysis

Our estimate of market risk exposure is presented for our fixed-rate and variable-rate long-term debt at September 30, 2017 for which an immediate adverse market movement causes a potential material impact on our financial condition, results of operations or the fair value of the debt. We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any

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expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. As of September 30, 2017, we did not hold any market risk sensitive instruments that were entered into for trading purposes.

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



DPL	At September 30, 2017				One percent
	Principal		Fair		interest rate
$ in millions	Amount		Value		risk
Long-term debt ^(a)
Variable-rate debt	$	548.0	$	548.0	$	5.5

Fixed-rate debt ^(b)	1,213.5		1,295.8		12.1

Total	$	1,761.5	$	1,843.8	$	17.6


(a)	Amounts exclude immaterial capital lease obligations


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



DP&L	At September 30, 2017				One percent
	Principal		Fair		interest rate
$ in millions	Amount		Value		risk
Long-term debt ^(a)
Variable-rate debt	$	441.7	$	441.7	$	4.4

Fixed-rate debt ^(b)	217.9		217.8		2.2

Total	$	659.6	$	659.5	$	6.6


(a)	Amounts exclude immaterial capital lease obligations


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

DPL’s long-term debt is comprised of both fixed-rate debt and variable-rate debt. In regard to fixed-rate debt, the interest rate risk with respect to DPL’s long-term debt primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s $1,295.8 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 $548.0 million variable-rate long-term debt outstanding as of September 30, 2017.

DP&L’s interest rate risk with respect to DP&L’s long-term debt primarily relates to the potential impact a decrease in interest rates of one percentage point has on the fair value of DP&L’s $217.8 million of fixed-rate debt and not on DP&L’s financial condition or DP&L’s results of operations. On the variable-rate debt, the interest rate risk with respect to DP&L’s long-term debt represents the potential impact of an increase of one percentage point in the interest rate has on DP&L’s results of operations related to DP&L’s $441.7 million variable-rate long-term debt outstanding as of September 30, 2017.

Credit Risk

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Critical Accounting Estimates

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

Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Historically, however, recorded estimates have not differed materially from actual results. Significant items subject to such judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits and intangible assets. Refer to our Form 10-K for the year ended December 31, 2016 for a complete listing of our critical accounting policies and estimates. There have been no material changes to these critical accounting policies and estimates.



ELECTRIC SALES AND CUSTOMERS (a)
	DPL		DP&L
	Three months ended		Three months ended
	September 30,		September 30,
	2017	2016	2017	2016
Electric Sales (millions of kWh)	3,975	4,810	3,836	4,586

Billed electric customers (end of period)	520,211	517,607	520,211	517,607


	Nine months ended		Nine months ended
	September 30,		September 30,
	2017	2016	2017	2016
Electric Sales (millions of kWh)	11,396	12,753	11,061	12,242

Billed electric customers (end of period)	520,211	517,607	520,211	517,607


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

Item 3 – Quantitative and Qualitative Disclosures about Market Risk

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

Item 4 – Controls and Procedures

Disclosure Controls and Procedures

Our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining our disclosure controls and procedures. These controls and procedures were designed to ensure that material information relating to us and our subsidiaries is communicated to the CEO and CFO. We evaluated these disclosure controls and procedures as of the end of the period covered by this report with the participation of our CEO and CFO. Based on this evaluation, our CEO and CFO concluded that, as of September 30, ~~2016,~~2017, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

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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.~~2017. In making this assessment, management used the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations (“COSO”) in 2013. There were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management and our ~~Board~~Boards of Directors are committed to the continued improvement of DPL's and DP&L'soverall ~~system~~systems of internal control over financial reporting.

Part II – Other Information

Item 1 – Legal Proceedings

In the normal course of business, we are subject to various lawsuits, actions, claims, and other proceedings. We are also, from time to time, involved in other reviews, investigations and proceedings by governmental and regulatory agencies regarding our business, certain of which may result in adverse judgments, settlements, fines,

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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~~2016 and ~~Forms10-Q~~Forms 10-Q for the quarters ended June 30, and March 31, ~~2016~~2017 and the Notes to DPL’s Consolidated Financial Statements and DP&L’s Financial Statements included therein contain descriptions of certain legal proceedings in which we are or were involved. The information in or incorporated by reference into this Item 1 to Part II is limited to certain recent developments concerning our legal proceedings and new legal proceedings, since the filing of such Forms 10-K and 10-Q, and should be read in conjunction with such Forms 10-K and 10-Q.

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

Item 1A – Risk Factors

A listing of the risk factors that we consider to be the most significant to a decision to invest in our securities is provided in our Form 10-K for the fiscal year ended December 31, ~~2015.~~2016. As of September 30, ~~2016,~~2017, there have been no material changes with respect to the risk factors disclosed in our Form 10-K. If any of the events described in our risk factors occur, it could have a material effect on our results of operations, financial condition and cash flows.

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

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

None

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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	2.1	Asset Contribution Agreement, dated as of September 28, 2017, by and between The Dayton Power and Light Company and AES Ohio Merger Sub, LLC	Exhibit 2.1 to Report on Form 8-K filed on October 2, 2017 (File No. 1-09052)
X	X	2.2	Agreement and Plan of Merger, dated as of September 28, 2017, by and between AES Ohio Merger Sub, LLC and AES Ohio Generation, LLC	Exhibit 2.2 to Report on Form 8-K filed on October 2, 2017 (File No. 1-09052)
X	X	4.1	~~Credit Agreement,~~ Fifty-First Supplemental Indenture dated ~~August 24, 2016, among~~as of September 29, 2017 between The Bank of New York Mellon, Trustee and 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~~October 2, 2017 (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)~~1-09052)
X		31(a)	Certification of Chief Executive Officer pursuant to ~~Section 302~~Rule 13a-14(a)/Rule 15d-14(a) of the ~~Sarbanes-Oxley~~Securities Exchange Act of ~~2002~~	~~Filed herewith~~1934, as ~~Exhibit 31(a)~~
X		~~31(b)~~	~~Certification of Chief Financial Officer~~ adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(a)
X		31(b)	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(b)
	X	31(c)	Certification of Chief Executive Officer pursuant to ~~Section 302~~Rule 13a-14(a)/Rule 15d-14(a) of the ~~Sarbanes-Oxley~~Securities Exchange Act of ~~2002~~	~~Filed herewith~~1934, as ~~Exhibit 31(c)~~
	X	~~31(d)~~	~~Certification of Chief Financial Officer~~ adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(c)
	X	31(d)	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(d)
X		32(a)	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section ~~906 of the Sarbanes-Oxley Act of 2002~~	~~Filed herewith~~1350, as ~~Exhibit 32(a)~~
X		~~32(b)~~	~~Certification of Chief Financial Officer~~ adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(a)
X		32(b)	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(b)
	X	32(c)	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section ~~906 of the Sarbanes-Oxley Act of 2002~~	~~Filed herewith~~1350, as ~~Exhibit 32(c)~~
	X	~~32(d)~~	~~Certification of Chief Financial Officer~~ adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(c)
	X	32(d)	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(d)
X	X	101.INS	XBRL Instance	Filed herewith as Exhibit 101.INS
X	X	101.SCH	XBRL Taxonomy Extension Schema	Filed herewith as Exhibit 101.SCH
X	X	101.CAL	XBRL Taxonomy Extension Calculation Linkbase	Filed herewith as Exhibit 101.CAL
X	X	101.DEF	XBRL Taxonomy Extension Definition Linkbase	Filed herewith as Exhibit 101.DEF
X	X	101.LAB	XBRL Taxonomy Extension Label Linkbase	Filed herewith as Exhibit 101.LAB
X	X	101.PRE	XBRL Taxonomy Extension Presentation Linkbase	Filed herewith as Exhibit 101.PRE

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

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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~~1, 2017	/s/ Kenneth J. Zagzebski
		Kenneth J. Zagzebski
		President and Chief Executive Officer
		(principal executive officer)

	November ~~3, 2016~~1, 2017	/s/ Craig L. Jackson
		Craig L. Jackson
		Chief Financial Officer
		(principal financial officer)

	November ~~3, 2016~~1, 2017	/s/ Kurt A. Tornquist
		Kurt A. Tornquist
		Controller
		(principal accounting officer)

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SIGNATURES

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



		The Dayton Power and Light Company
		(Registrant)

Date:	November ~~3, 2016~~1, 2017	/s/ Thomas A. Raga
		Thomas A. Raga
		President and Chief Executive Officer
		(principal executive officer)

	November ~~3, 2016~~1, 2017	/s/ Craig L. Jackson
		Craig L. Jackson
		Chief Financial Officer
		(principal financial officer)

	November ~~3, 2016~~1, 2017	/s/ Kurt A. Tornquist
		Kurt A. Tornquist
		Controller
		(principal accounting officer)

93115



$ 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



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



	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