UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

Amendment No. 1

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

OR

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to ____________

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer  Identification No.
1-9052	DPL INC.	31-1163136
	(An Ohio Corporation)
	1065 Woodman Drive Dayton, Ohio 45432
	937-224-6000
1-2385	THE DAYTON POWER AND LIGHT COMPANY	31-0258470
	(An Ohio Corporation)
	1065 Woodman Drive Dayton, Ohio 45432
	937-224-6000

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

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

Indicate by check mark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

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

1

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 x	No o
The Dayton Power and Light Company	Yes o	No x

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. During 2015, DPL Inc. was a voluntary filer until its May 29, 2015 Registration Statement on Form S-4 filed with the Securities and Exchange Commission was declared effective on June 12, 2015. DPL Inc. 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 website, 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K/A or any amendment to this Form 10-K/A.

DPL Inc.	x
The Dayton Power and Light Company	x

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

	Large		Non-	Smaller
	accelerated	Accelerated	accelerated	reporting
	filer	filer	filer	company
DPL Inc.	o	o	x	o
The Dayton Power and Light Company	o	o	x	o

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

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

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

2

At December 31, 2015, 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

Documents incorporated by reference: None

This combined Form 10-K/A 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.

THE REGISTRANTS MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND (b) OF FORM 10-K/A AND ARE THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT.

3

Explanatory Note

We are filing this Amendment No. 1 (“Form 10-K/A”) to our combined Annual Report on Form 10-K for the fiscal year ended December 31, 2015, as filed with the Securities and Exchange Commission (the “SEC”) on February 24, 2016 (the “Form 10-K”), to correct the following inadvertent administrative error: the Reports of Independent Registered Public Accounting Firm previously filed with the Form 10-K have been amended to include the electronic signatures of Ernst & Young LLP on such reports for both DPL Inc. and The Dayton Power and Light Company, which signatures had been obtained prior to our filing the Form 10-K.

In accordance with Rule 12b-15 under the Securities Exchange Act of 1934, as amended, each item of the Form 10-K that is amended by this Form 10-K/A is restated in its entirety, and this Form 10-K/A is accompanied by restated and re-executed certifications on Exhibits 31(a) – (d) and Exhibits 32(a) – (d) by our Chief Executive Officer and Chief Financial Officer.

This Form 10-K/A speaks as of the original filing date of the Form 10-K and does not reflect any events that may have occurred subsequent to the original filing date. Except as described above, no other changes have been made to the Form 10-K and we are not amending any other part of, or updating any other disclosures made in, the Form 10K.

4

DPL Inc. and The Dayton Power and Light Company

Table of Contents

Amendment No. 1 to Annual Report on Form 10-K

Fiscal Year Ended December 31, 2015

Glossary of Terms	6
Part II
Item 8 – Financial Statements and Supplementary Data
DPL Inc.	11
The Dayton Power and Light Company	70
Part IV
Item 15 – Exhibits and Financial Statement Schedules	122
Signatures	127

5

GLOSSARY OF TERMS

The following select terms, abbreviations or acronyms are used in this Form 10-K/A:

Abbreviation or Acronym	Definition
AEP Generation	AEP Generation Resources Inc., a subsidiary of American Electric Power Company, Inc. (“AEP”). Columbus Southern Power Company merged into the Ohio Power Company, another subsidiary of AEP, effective December 31, 2011. The Ohio Power generating assets (including jointly-owned units) were transferred into AEP Generation, effective January 1, 2014.
AER	Alternative Energy Rider which allows DP&L to recover costs related to meeting the Ohio renewable portfolio standards.
AES	The AES Corporation, a global power company, the ultimate parent company of DPL
AES Ohio Generation	AES Ohio Generation, LLC (formerly DPLE), a wholly-owned subsidiary of DPL that owns and operates peaking generation facilities from which it makes wholesale sales
AMI	Advanced Metering Infrastructure
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
ASU	Accounting Standards Update
CFTC	Commodity Futures Trading Commission
CAA	U.S. Clean Air Act
CAIR	Clean Air Interstate Rule
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.
CCEM	Customer Conservation and Energy Management
CO2	Carbon Dioxide
ComEd	Commonwealth Edison
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 will operate under the CP construct starting June 1, 2016.
CRES	Competitive Retail Electric Service
CSAPR	Cross-State Air Pollution Rule
CWA	U.S. Clean Water Act
Dark spread	A common metric used to estimate returns over fuel costs of coal-fired electric generating units
D.C. Circuit Court	United States Court of Appeals for the District of Columbia Circuit
DPL	DPL Inc.
DPLE	DPL Energy, LLC, a wholly-owned subsidiary of DPL that owns and operates peaking generation facilities from which it makes wholesale sales (renamed AES Ohio Generation, LLC effective February 1, 2016)
DPLER	DPL Energy Resources, Inc., formerly a wholly-owned subsidiary of DPL which sold competitive electric energy and other energy services, including sales by a wholly-owned subsidiary, MC Squared, which DPLER sold on April 1, 2015. DPLER was sold by DPL on January 1, 2016. The DPLER sale agreement was signed on December 28, 2015.

6

GLOSSARY OF TERMS (cont.)
Abbreviation or Acronym	Definition
DP&L	The Dayton Power and Light Company, the principal subsidiary of DPL and a public utility which sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. DP&L is wholly-owned by DPL
Duke Energy	Affiliates of Duke Energy with which DP&L co-owns electric generating units and transmission lines in Ohio (Duke Energy Ohio, Inc.)
Dynegy	Dynegy, Inc., the parent of various subsidiaries that, along with AEP Generation and DP&L, co-owns electric generating units in Ohio
EBITDA	Earnings before interest, taxes, depreciation and amortization
EGU	Electric generating unit
ERISA	The Employee Retirement Income Security Act of 1974
ESP	The Electric Security Plan is a cost-based plan that a utility may file with the PUCO to establish SSO rates pursuant to Ohio law
FASB	Financial Accounting Standards Board
FASC	FASB Accounting Standards Codification
FASC 805	FASB Accounting Standards Codification 805, “Business Combinations”
FERC	Federal Energy Regulatory Commission
FGD	Flue Gas Desulfurization
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
FTRs	Financial Transmission Rights
GAAP	Generally Accepted Accounting Principles in the United States of America
GHG	Greenhouse gas
IFRS	International Financial Reporting Standards
kV	Kilovolts, 1,000 volts
kWh	Kilowatt hour
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
MATS	Mercury and Air Toxics Standards
MC Squared	MC Squared Energy Services, LLC, a retail electricity supplier formerly wholly-owned by DPLER, sold on April 1, 2015
Merger	The merger of DPL and Dolphin Sub, Inc. (a wholly-owned subsidiary of AES) in accordance with the terms of an Agreement and Plan of Merger dated April 19, 2011 among DPL, AES and Dolphin Sub, Inc. a wholly-owned subsidiary of AES. On the Merger date, DPL became a wholly-owned subsidiary of AES.
Merger date	November 28, 2011, the date of the closing of the merger of DPL and Dolphin Sub, Inc.
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 relative to jointly-owned facilities operated by DP&L
MW	Megawatt
MWh	Megawatt hour
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
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

7

GLOSSARY OF TERMS (cont.)
Abbreviation or Acronym	Definition
NPDES	National Pollutant Discharge Elimination System
NSPS	New Source Performance Standards
NSR	New Source Review is a preconstruction permitting program regulating new or significantly modified sources of air pollution
NYMEX	New York Mercantile Exchange
OAQDA	Ohio Air Quality Development Authority
OCC	Ohio Consumers’ Counsel
OCI	Other Comprehensive Income
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
PPM	Parts per million
PRP	Potentially Responsible Party
Predecessor	DPL prior to the Merger date
PUCO	Public Utilities Commission of Ohio
ROE	Return on equity
RPM	The Reliability Pricing Model was PJM’s capacity construct.
RTO	Regional Transmission Organization
SB 221	Ohio Senate Bill 221, is an Ohio electric energy bill that was signed by the Governor on May 1, 2008 and went into effect July 31, 2008. This law required all Ohio distribution utilities to file either an ESP or MRO to be in effect January 1, 2009. The law also contains, among other things, annual targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards.
SB 310	Ohio Senate Bill 310, an Ohio electric energy bill that was passed in May 2014 that required all Ohio utilities to show on each bill the approximate cost of complying with renewable energy, energy efficiency and peak demand requirements.  It froze the Ohio renewable and energy efficiency annual targets for two year and required a legislative committee to evaluate whether or not the targets should continue.
SCR	Selective Catalytic Reduction
SEC	Securities and Exchange Commission
SEET	Significantly Excessive Earnings Test
Service Company	AES US Services, LLC, the shared services affiliate providing accounting, finance, and other support services to AES’ U.S. SBU businesses
SFAS	Statement of Financial Accounting Standards
SIP	A State Implementation Plan is a plan for complying with the federal CAA, administered by the USEPA. The SIP consists of narrative, rules, technical documentation and agreements that an individual state will use to clean up polluted areas.
SO2	Sulfur Dioxide
SO3	Sulfur Trioxide
SSO	Standard Service Offer represents the retail transmission, distribution and generation services offered by the utility through regulated rates, authorized by the PUCO
SSR	Service Stability Rider
Successor	DPL after the Merger
TCRR	Transmission Cost Recovery Rider
TCRR-B	Transmission Cost Recovery Rider – Bypassable

8

GLOSSARY OF TERMS (cont.)
Abbreviation or Acronym	Definition
TCRR-N	Transmission Cost Recovery Rider – Nonbypassable
USEPA	U. S. Environmental Protection Agency
USF	The Universal Service Fund (USF) 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

9

PART II

Item 8 – Financial Statements and Supplementary Data

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 clearly be noted in the section.

10

FINANCIAL STATEMENTS 

DPL INC.

11

Report of Independent Registered Public Accounting Firm

To the Board of Directors of DPL Inc.

We have audited the accompanying consolidated balance sheets of DPL Inc. as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income/(loss), cash flows, and shareholder’s equity for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule “Schedule II - Valuation and Qualifying Accounts” for each of the three years in the period ended December 31, 2015. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of DPL Inc. at December 31, 2015 and 2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

February 23, 2016

Indianapolis, Indiana

12

DPL INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
	Years ended December 31,
$ in millions	2015			2014			2013
Revenues	$	1,612.8		$	1,716.5		$	1,579.0
Cost of revenues:
Fuel	259.8			304.5			366.7
Purchased power	562.6			587.9			383.0
Total cost of revenues	822.4			892.4			749.7
Gross margin	790.4			824.1			829.3
Operating expenses:
Operation and maintenance	361.3			362.4			365.7
Depreciation and amortization	134.6			135.6			129.2
General taxes	87.0			87.8			76.8
Goodwill impairment	317.0			—			306.3
Fixed-asset impairment	—			11.5			26.2
Other	0.4			(3.9		)	2.5
Total operating expenses	900.3			593.4			906.7
Operating income / (loss)	(109.9		)	230.7			(77.4		)
Other income / (expense), net
Investment income	0.2			0.9			1.4
Interest expense	(118.3		)	(126.6		)	(124.0		)
Charge for early redemption of debt	(2.1		)	(30.9		)	(2.8		)
Other deductions	(1.3		)	(1.5		)	(3.0		)
Other expense, net	(121.5		)	(158.1		)	(128.4		)
Earnings (loss) from continuing operations before income tax	(231.4		)	72.6			(205.8		)
Income tax expense from continuing operations	20.0			15.4			19.8
Net income / (loss) from continuing operations	(251.4		)	57.2			(225.6		)
Discontinued operations (Note 16)
Income / (loss) from discontinued operations	11.4			(129.2		)	6.0
Income tax expense / (benefit)	(1.0		)	2.6			2.4
Discontinued operations	12.4			(131.8		)	3.6
Net loss	$	(239.0	)	$	(74.6	)	$	(222.0	)

See Notes to Consolidated Financial Statements.

13

DPL INC.
STATEMENTS OF COMPREHENSIVE LOSS
	Years ended December 31,
$ in millions	2015			2014			2013
Net loss	$	(239.0	)	$	(74.6	)	$	(222.0	)
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax benefit / (expense) of $0.1, $0.2 and $0.6 for each respective period	(0.1		)	(0.3		)	(1.2		)
Reclassification to earnings, net of income tax benefit / (expense) of $0.0, ($0.2) and ($0.7) for each respective period	—			0.2			1.4
Total change in fair value of available-for-sale securities	(0.1		)	(0.1		)	0.2
Derivative activity:
Change in derivative fair value, net of income tax benefit / (expense) of ($10.3), $10.3 and ($10.6) for each respective period	18.2			(19.0		)	19.7
Reclassification to earnings, net of income tax benefit / (expense) of $5.4, ($9.5) and ($2.3) for each respective period	(10.0		)	16.9			3.4
Total change in fair value of derivatives	8.2			(2.1		)	23.1
Pension and postretirement activity:
Prior service cost for the period, net of income tax benefit / (expense) of $0.0, $1.3 and $0.0 for each respective period	—			(2.2		)	—
Net gain / (loss) for the period, net of income tax benefit / (expense) of ($1.2), $7.1 and ($2.7) for each respective period	1.6			(12.7		)	4.9
Reclassification to earnings, net of income tax benefit / (expense) of ($0.2), $0.0 and $0.3 for each respective period	0.2			—			0.3
Total change in unfunded pension and postretirement	1.8			(14.9		)	5.2
Other comprehensive income / (loss)	9.9			(17.1		)	28.5
Net comprehensive loss	$	(229.1	)	$	(91.7	)	$	(193.5	)

See Notes to Consolidated Financial Statements.

14

DPL INC.
CONSOLIDATED BALANCE SHEETS
$ in millions	December 31, 2015			December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	32.4		$	17.0
Restricted cash	92.7			16.8
Accounts receivable, net (Note 2)	120.9			136.5
Inventories (Note 2)	109.1			100.2
Taxes applicable to subsequent years	81.2			77.8
Regulatory assets, current (Note 3)	14.4			44.2
Other prepayments and current assets	46.6			38.9
Assets held for sale - current (Note 16)	62.2			67.3
Total current assets	559.5			498.7
Property, plant and equipment:
Property, plant and equipment	2,909.0			2,754.1
Less: Accumulated depreciation and amortization	(432.3		)	(317.9		)
	2,476.7			2,436.2
Construction work in process	85.0			76.4
Total net property, plant and equipment	2,561.7			2,512.6
Other non-current assets:
Regulatory assets, non-current (Note 3)	179.9			167.5
Goodwill (Note 7)	—			317.0
Intangible assets, net of amortization (Note 7)	5.0			7.8
Other deferred assets	34.7			39.7
Assets held for sale - non-current (Note 16)	—			34.5
Total other non-current assets	219.6			566.5
Total Assets	$	3,340.8		$	3,577.8
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Current portion - long-term debt (Note 8)	$	574.9		$	20.1
Accounts payable	97.5			94.4
Accrued taxes	142.4			102.6
Accrued interest	21.4			27.2
Customer security deposits	15.2			14.4
Regulatory liabilities, current (Note 3)	24.4			4.4
Insurance and claims costs	5.9			6.4
Other current liabilities	54.5			46.3
Deposit received on sale of DPLER (Note 16)	75.5			—
Liabilities held for sale - current (Note 16)	1.6			17.1
Total current liabilities	1,013.3			332.9
Non-current liabilities:
Long-term debt (Note 8)	1,434.5			2,139.6
Deferred taxes (Note 9)	568.7			587.3
Taxes payable	84.1			80.7
Regulatory liabilities, non-current (Note 3)	127.0			124.1
Pension, retiree and other benefits (Note 10)	87.1			95.9
Other deferred credits	88.3			50.5
Liabilities held for sale - non-current (Note 16)	—			0.2
Total non-current liabilities	2,389.7			3,078.3
Redeemable preferred stock of subsidiary (Note 11)	18.4			18.4
Commitments and contingencies (Note 12)
Common shareholder's equity:
Common stock:
1,500 shares authorized; 1 share issued and outstanding
at December 31, 2015 and 2014	—			—
Other paid-in capital	2,237.7			2,237.4
Accumulated other comprehensive income	17.4			7.5
Retained earnings / (deficit)	(2,335.7		)	(2,096.7		)
Total common shareholder's equity	(80.6		)	148.2
Total Liabilities and Shareholder's Equity	$	3,340.8		$	3,577.8

See Notes to Consolidated Financial Statements.

15

DPL INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Years ended December 31,
$ in millions	2015			2014			2013
Cash flows from operating activities:
Net loss	$	(239.0	)	$	(74.6	)	$	(222.0	)
Adjustments to reconcile Net loss to Net cash from operating activities
Depreciation and amortization	138.8			139.8			132.9
Amortization of intangibles	—			1.2			7.1
Amortization of debt market value adjustments	(1.1		)	0.3			(14.4		)
Amortization of deferred financing costs	5.9			6.3			5.0
Unrealized loss on derivatives	5.8			3.0			5.9
Deferred income taxes	(17.1		)	17.7			24.0
Charge for early redemption of debt	2.1			30.9			2.8
Goodwill impairment (a)	317.0			135.8			306.3
Fixed-asset impairment	—			11.5			26.2
Loss / (Gain) on asset disposal	0.4			(3.9		)	2.5
Changes in certain assets and liabilities:
Accounts receivable	43.4			0.5			7.4
Inventories	(9.0		)	(24.9		)	27.4
Prepaid taxes	(1.3		)	(0.9		)	0.7
Taxes applicable to subsequent years	(3.4		)	(7.1		)	(1.4		)
Deferred regulatory costs, net	21.8			5.4			7.6
Accounts payable	(5.1		)	32.1			(5.8		)
Accrued taxes payable	43.8			20.7			(5.5		)
Accrued interest payable	(5.7		)	(1.3		)	(3.3		)
Other current and deferred liabilities	(10.4		)	(40.6		)	1.5
Pension, retiree and other benefits	(0.7		)	19.1			1.8
Unamortized investment tax credit	(0.5		)	(0.5		)	(0.5		)
Insurance and claims costs	(0.5		)	(0.2		)	(4.8		)
Other	23.3			(26.2		)	1.4
Net cash from operating activities	308.5			244.1			302.8
Cash flows from investing activities:
Capital expenditures	(137.2		)	(118.1		)	(124.4		)
Proceeds from sale of property	1.3			10.7			0.8
Insurance proceeds	—			0.3			7.6
Purchase of renewable energy credits	(0.8		)	(3.5		)	(3.9		)
Decrease / (increase) in restricted cash	(0.4		)	(3.3		)	(2.8		)
Other investing activities, net	0.4			1.3			(1.2		)
Net cash from investing activities	(136.7		)	(112.6		)	(123.9		)
Cash flows from financing activities:
Deferred financing costs	(6.9		)	(3.6		)	(15.3		)
Retirement of debt	(474.5		)	(335.0		)	(945.1		)
Premium paid for early redemption of debt	—			(29.1		)	(2.4		)
Issuance of long-term debt	325.0			200.0			645.0
Borrowings from revolving credit facilities	80.0			190.0			50.0
Repayment of borrowings from revolving credit facilities	(80.0		)	(190.0		)	(50.0		)
Net cash from financing activities	(156.4		)	(167.7		)	(317.8		)
Cash and cash equivalents:
Net increase / (decrease) in cash	15.4			(36.2		)	(138.9		)
Balance at beginning of period	17.0			53.2			192.1
Cash and cash equivalents at end of period	$	32.4		$	17.0		$	53.2
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	111.6		$	117.3		$	137.5
Income taxes paid / (refunded), net	$	0.8		$	0.7		$	(5.2	)
Non-cash financing and investing activities:
Accruals for capital expenditures	$	18.6		$	16.3		$	14.7

(a) Goodwill impairment of $135.8 million in 2014 has been reclassified to Discontinued operations in the Consolidated Statement of Operations.

See Notes to Consolidated Financial Statements.

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DPL INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
	Common Stock (a)
$ in millions (except Outstanding Shares)	Outstanding Shares	Amount		Other Paid-in Capital		Accumulated Other Comprehensive Income / (Loss)			Retained Earnings/ (Deficit)			Total
Year ended December 31, 2013
Beginning balance	1	$	—	$	2,236.7	$	(3.9	)	$	(1,806.0	)	$	426.8
Net comprehensive loss						28.5			(222.0		)	(193.5		)
Common stock dividends									—			—
Other (b)				0.3					5.9			6.2
Ending balance	1	—		2,237.0		24.6			(2,022.1		)	239.5
Year ended December 31, 2014
Net comprehensive loss						(17.1		)	(74.6		)	(91.7		)
Other				0.4					—			0.4
Ending balance	1	—		2,237.4		7.5			(2,096.7		)	148.2
Year ended December 31, 2015
Net comprehensive loss						9.9			(239.0		)	(229.1		)
Other				0.3								0.3
Ending balance	1	$	—	$	2,237.7	$	17.4		$	(2,335.7	)	$	(80.6	)

(a) 1,500 shares authorized

(b) $5.9 million of dividends declared in 2012 were reversed in 2013.

See Notes to Consolidated Financial Statements.

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DPL Inc.

Notes to Consolidated Financial Statements

For the years ended December 31,2015, 2014 and 2013

Note 1 – Overview and Summary of Significant Accounting Policies

Description of Business

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’sone reportable segment is the Utility segment, comprised of its DP&L subsidiary. See Note 14 – Business Segments for more information relating to reportable segments. The terms “we”, “us”, “our” and “ours” are used to refer to DPL and its subsidiaries.

On November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly-owned subsidiary of AES. Following the merger of DPL and Dolphin Subsidiary II, Inc., DPL became an indirectly wholly-owned subsidiary of AES.

DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission services are still regulated. DP&L has the exclusive right to provide such service to its approximately517,000customers located in West Central Ohio. Additionally, DP&L procures and provides retail SSO electric service to residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio and generates electricity atfivecoal-fired power stations. Beginning in 2014, DP&L no longer supplied100% of the generation for SSO customers and starting January 2016, SSO is now100%competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the general economic conditions, seasonal weather patterns of the area and the market price of electricity. DP&L sells any excess energy and capacity into the wholesale market. DP&L also sold electricity to DPLER, an affiliate, to satisfy the electric requirements of its retail customers.

In accordance with the ESP Order, on December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets. On July 14, 2014, DP&L announced its decision to retain DP&L’s generation assets. On September 17, 2014 the PUCO ordered that DP&L’s application as amended and updated was approved. DP&L is required to sell or transfer its generation assets by January 1, 2017 and continues to look at multiple options to effectuate the separation, including transfer into an unregulated affiliate of DPL or through a sale.

DPLER was sold by DPL on January 1, 2016. DPLER sold competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER had approximately125,000customers located throughout Ohio. DPLER’s operations included those of its wholly-owned subsidiary MC Squared through April 1, 2015, when DPLER sold MC Squared. Approximately110,000of DPLER’s customers were also electric distribution customers of DP&L. DPLER did not own any transmission or generation assets, and it purchased all of its electric energy from DP&L to meet its sales obligations. DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the area. See Note 16 – Discontinued Operations for more information.

DPL’s other significant subsidiaries include DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity, and MVIC, our captive insurance company that provides insurance services to us and our other subsidiaries. Effective February 1, 2016, DPLE was renamed AES Ohio Generation, LLC. DPL owns all of the common stock of its subsidiaries.

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

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

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DPL and its subsidiaries employed 1,219 people at January 31, 2016, of which 1,189 were employed by DP&L. Approximately 60% of all DPL employees are under a collective bargaining agreement which expires on October 31, 2017.

Financial Statement Presentation

We prepare Consolidated Financial Statements for DPL. DPL’s Consolidated Financial Statements include the accounts of DPL and its wholly-owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP. DP&L’s undivided ownership interests in certain coal-fired generating stations are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger date. Operating revenues and expenses are included on a pro rata basis in the corresponding lines in the Consolidated Statement of Operations. See Note 4 – Property, Plant and Equipment for more information.

All material intercompany accounts and transactions are eliminated in consolidation.

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

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; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits; goodwill; and intangibles.

Valuation of Goodwill

FASC 350, “Intangibles – Goodwill and Other”, requires that goodwill be tested for impairment at the reporting unit level at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. See Note 7 – Goodwill and Other Intangible Assets for information regarding the impairments of goodwill in 2015, 2014 and 2013.

Revenue Recognition

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our statements of operations using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class.

All of the power produced at the generation stations is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Consolidated Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity.

Allowance for Uncollectible Accounts

We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collections efforts have been exhausted.

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Property, Plant and Equipment

We record our ownership share of our undivided interest in jointly-held stations as an asset in property, plant and equipment. New property, plant and equipment additions are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $2.0 million, $1.5 million and $1.5 million in the years ended December 31, 2015, 2014 and 2013, respectively.

For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest.

For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization.

Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable. See Note 15 – Fixed-asset Impairment for more information.

Repairs and Maintenance

Costs associated with maintenance activities, primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.

Depreciation

Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates that approximated 4.6% in 2015, 5.3% in 2014 and 5.8% in 2013. Depreciation expense was $125.9 million, $128.1 million and $120.9 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Regulatory Accounting

As a regulated utility, we apply the provisions of FASC 980 “Regulated Operations”, which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DP&L expects to incur in the future.

The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 3 – Regulatory Assets and Liabilities for more information.

Inventories

Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations.

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Intangibles

Intangibles include emission allowances and renewable energy credits. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are carried on a weighted average cost basis and amortized as they are used or retired. See Note 7 – Goodwill and Other Intangible Assets for additional information.

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish an allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Our tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting. Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. Our policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statement of Operations.

Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets with a corresponding deferred tax liability. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 3 – Regulatory Assets and Liabilities for additional information.

DPL and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 9 – Income Taxes for additional information.

Financial Instruments

We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholders’ equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost bases for public equity security and fixed maturity investments are average cost and amortized cost, respectively.

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. DP&L’s excise taxes and certain other taxes are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements of Operations. The amounts for the years ended December 31, 2015, 2014 and 2013, were $49.9 million, $50.8 million and $50.5 million, respectively.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. At December 31, 2015, restricted cash also includes cash received in connection with the sale of DPLER on January 1, 2016. See Note 16 – Discontinued Operations for additional information regarding the sale of DPLER.

Financial Derivatives

All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.

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We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. These purchases are used to hedge our full load requirements. We also hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in fair value being recorded within accumulated other comprehensive income, a component of shareholder’s equity. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 6 – Derivative Instruments and Hedging Activities for additional information.

Insurance and Claims Costs

In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us, our subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, and property damage on an ongoing basis. MVIC maintains an active run-off policy for directors’ and officers’ liability and fiduciary through their expiration in 2017, which may or may not be renewed at that time. Insurance and Claims Costs on DPL’s Consolidated Balance Sheets associated with MVIC include estimated liabilities of approximately $5.9 million and $6.4 million at December 31, 2015 and 2014, respectively. In addition, DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. DP&L has estimated liabilities for medical, life, and disability reserves for claims costs below certain coverage thresholds of third-party providers of approximately $13.7 million and $15.6 million at December 31, 2015 and 2014, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined using certain assumptions. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.

Pension and Postretirement Benefits

We recognize, in our Consolidated Balance Sheets, an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status recognized in AOCI, except for those portions of our pension and postretirement obligations that can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans.

Effective January 1, 2016, we will apply a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and post-retirement plans. This approach is consistent with the requirements of ASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation.

The change in discount rate approach did not have an impact on the measurement of the benefit obligations at December 31, 2015, nor will it impact future remeasurements. This change in approach will impact the service cost and interest cost recorded in 2016 and future years. It will also impact the actuarial gains and losses recorded in future years, as well as the amortization thereof.

22

The expected 2016 service costs and interest costs included in Note 10 – Benefit Plans reflect the change in methodology described above. The impact of the change in approach on expected service costs in 2016 is shown below:

$ in millions	Expected 2016 Service Cost							Expected 2016 Interest Cost
	Disaggregated rate approach		Aggregate rate approach		Impact of change			Disaggregated rate approach		Aggregate rate approach		Impact of change
Total Pension	$	5.7	$	6.1	$	(0.4	)	$	14.8	$	17.9	$	(3.1	)
Total Postretirement Benefits	$	0.2	$	0.2	$	—		$	0.6	$	0.7	$	(0.1	)
Total	$	5.9	$	6.3	$	(0.4	)	$	15.4	$	18.6	$	(3.2	)

See Note 10 – Benefit Plans for more information.

Related Party Transactions

In the normal course of business, DPL enters into transactions with related parties. All material intercompany accounts and transactions are eliminated in DPL’s Consolidated Financial Statements.

See Note 13 – Related Party Transactions for more information on Related Party Transactions.

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 December 31, 2015 and 2014, respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $15.6 million and $15.6 million at December 31, 2015 and December 31, 2014, respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 8 – 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.

New accounting pronouncements adopted

ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes

Effective December 31, 2015, we prospectively adopted ASU No. 2015-17, which requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. As a result, each jurisdiction will now only have one net noncurrent deferred tax asset or liability. The guidance does not change the existing requirement that only permits offsetting within a jurisdiction; that is, companies will remain prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. Additionally, the current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the update. As we elected to apply this ASU prospectively, prior periods were not adjusted.

ASU No. 2015-13, Derivatives and Hedging (Topic 815):Derivatives and Hedging: Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Market

In August 2015, the FASB issued ASU No. 2015-13, which resolves the diversity in practice resulting from determining whether certain contracts qualify for the normal purchases and normal sales scope exception under ASC Topic 815, Derivatives and Hedging. This standard clarifies that entities would not be precluded from applying the normal purchases and normal sales exception to certain forward contracts that necessitate the transmission of electricity through, or delivery to a location within, a nodal energy market. The standard is effective upon issuance and should be applied prospectively. As we had designated qualifying contracts as normal purchase or normal sales, there was no impact on our financial statements upon adoption of this standard.

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Accounting pronouncements issued but not yet effective

ASU No. 2016-01, Financial Instruments — Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, which was designed to improve the recognition and measurement of financial instruments through targeted changes to existing GAAP. The guidance requires equity investments (except those that are accounted for under the equity method of accounting or result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income; that entities use the exit price notion when measuring financial instrument fair values; that an entity separate presentation of financial assets and liabilities by measurement category and form of financial asset on the Balance Sheets or Notes to the financial statements; that an entity present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk (or "own credit") when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. Also, the standard eliminates the requirement for public entities to disclose the methods and significant assumptions used to estimate the fair value required to be disclosed for financial instruments measured at amortized cost on the Balance Sheets. The standard is effective beginning with interim periods starting after December 31, 2017 and cannot be applied early. We are currently evaluating the applicability and materiality of the standard, but we do not anticipate a material impact on our consolidated financial statements.

ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments

In September 2015, the FASB issued ASU 2015-16, which simplifies the measurement-period adjustments in business combinations. It eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. An acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. The standard is effective for public entities for annual reporting periods beginning after December 15, 2015, and interim periods therein. Early adoption is permitted for financial statements that have not been issued. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date of this standard. We will adopt this standard on January 1, 2016, which is not expected to have a material impact on our consolidated financial statements.

ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30)

In April 2015, the FASB issued ASU No. 2015-03, which simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein, and requires the use of the full retrospective approach. Early adoption is permitted for financial statements that have not been previously issued. As of December 31, 2015, DPL had approximately $16.1 million in deferred financing costs classified in other current and other non-current assets that would be reclassified to reduce the related debt liabilities upon adoption of ASU No. 2015-03.

ASU No. 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements

In August 2015, the FASB issued ASU No. 2015-15, which clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This standard should be adopted concurrent with adoption of ASU 2015-03 (which is described above). As of December 31, 2015, we had deferred financing costs related to lines of credit of approximately $3.1 million recorded within Other noncurrent assets that would not be reclassified upon adoption of this standard.

ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory

In July 2015, the FASB issued ASU No. 2015-11, which simplifies the subsequent measurement of inventory. It replaces the current lower of cost or market test with a lower of cost or net realizable value test. The standard is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted. The new guidance must be applied prospectively. As we already used the net realizable value to make lower of cost or market determinations, there will be no impact on our financial statements upon adoption of this standard.

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ASU No. 2015-05, Intangibles – Goodwill and Other: Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued ASU No. 2015-05, which clarifies how customers in cloud computing arrangements should determine whether the arrangement includes a software license and eliminates the existing requirement for customers to account for software licenses they acquired by analogizing to the accounting guidance on leases. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits the use of a prospective or retrospective approach. As all of our cloud computing arrangements will continue to be accounted for as service agreements, there will be no impact on our financial statements upon the adoption of this standard.

ASU No. 2014-05, Presentation of Financial Statements: Going Concern

The FASB recently issued ASU 2014-15 “Presentation of Financial Statements - Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern)” effective for annual and interim periods ending after December 15, 2016. ASU 2014-15 requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of: principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern. This ASU is not expected to have any impact on our overall results of operations, financial position or cash flows.

ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)

In May 2014, the FASB issued ASU No. 2014-09, which clarifies principles for recognizing revenue and will result in a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The objective of the new standard is to provide 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 of when it is recognized. 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. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contract with Customers (Topic 606): Deferral of the Effective Date, which deferred the effective date of ASU 2014-09 by one year, resulting in the new revenue standard being effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. Early adoption is now permitted only as of the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). The standard permits the use of either a full retrospective or modified retrospective approach. We have not yet selected a transition method and are currently evaluating the impact of adopting the standard on our financial statements.

ASU No. 2015-02, Consolidation – Amendments to the Consolidation Analysis (Topic 810)

In February 2015, the FASB issued ASU 2015-02, which makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the Variable Interest Entity (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. The standard is effective for annual periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. We do not expect this standard to have an impact on our financial statements upon adoption.

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Note 2 – Supplemental Financial Information

	December 31,
$ in millions	2015			2014
Accounts receivable, net
Unbilled revenue	$	43.3		$	49.1
Customer receivables	56.4			70.1
Amounts due from partners in jointly-owned stations	16.0			15.2
Other	6.0			3.0
Provisions for uncollectible accounts	(0.8		)	(0.9		)
Total accounts receivable, net	$	120.9		$	136.5
Inventories
Fuel and limestone	$	72.2		$	65.3
Plant materials and supplies	34.9			33.5
Other	2.0			1.4
Total inventories, at average cost	$	109.1		$	100.2

Accounts receivable of $31.0 million and $64.4 million as of December 31, 2015 and 2014 have been excluded from the above table as they have been reclassified as "Assets held for sale". See Note 16 – Discontinued Operations.

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Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2015, 2014 and 2013 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) Components	Affected line item in the Consolidated Statements of Operations	Years ended December 31,
$ in millions		2015			2014			2013
Gains and losses on Available-for-sale securities activity (Note 5):
	Other income / (deductions)	$	—		$	0.4		$	2.1
	Tax expense	—			(0.2		)	(0.7		)
	Net of income taxes	—			0.2			1.4
Gains and losses on cash flow hedges (Note 6):
	Interest Expense	(1.1		)	(1.3		)	—
	Revenue	(18.7		)	28.4			2.2
	Purchased power	4.4			(0.7		)	3.5
	Total before income taxes	(15.4		)	26.4			5.7
	Tax benefit / (expense)	5.4			(9.5		)	(2.3		)
	Net of income taxes	(10.0		)	16.9			3.4
Amortization of defined benefit pension items (Note 10):
	Operations and maintenance	0.4			—			—
	Tax expense	(0.2		)	—			0.3
	Net of income taxes	0.2			—			0.3
Total reclassifications for the period, net of income taxes		$	(9.8	)	$	17.1		$	5.1

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The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2015 and 2014 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 at December 31, 2013	$	0.6		$	20.6		$	3.4		$	24.6
Other comprehensive loss before reclassifications	(0.3		)	(19.0		)	(14.9		)	(34.2		)
Amounts reclassified from accumulated other comprehensive income / (loss)	0.2			16.9			—			17.1
Net current period other comprehensive loss	(0.1		)	(2.1		)	(14.9		)	(17.1		)
Balance at December 31, 2014	0.5			18.5			(11.5		)	7.5
Other comprehensive income / (loss) before reclassifications	(0.1		)	18.2			1.6			19.7
Amounts reclassified from accumulated other comprehensive income / (loss)	—			(10.0		)	0.2			(9.8		)
Net current period other comprehensive income / (loss)	(0.1		)	8.2			1.8			9.9
Balance at December 31, 2015	$	0.4		$	26.7		$	(9.7	)	$	17.4

Note 3 – Regulatory Assets and Liabilities

In accordance with FASC 980, we have recognized total regulatory assets of $194.3 million and $211.7 million at December 31, 2015 and 2014, respectively, and total regulatory liabilities of $151.4 million and $128.5 million at December 31, 2015 and 2014, respectively. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 1 – Overview and Summary of Significant Accounting Policies for accounting policies regarding Regulatory Assets and Liabilities.

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The following table presents DPL’s Regulatory assets and liabilities:

			December 31,
$ in millions	Type of Recovery	Amortization Through	2015		2014
Regulatory assets, current:
Fuel and purchased power recovery costs	A	2016	$	13.9	$	16.3
Economic development costs	A	2016	0.5		2.1
Deferred storm costs	B	2015	—		22.3
Energy efficiency program	A	2016	—		1.8
Other miscellaneous	A	2016	—		1.7
Total regulatory assets, current			14.4		44.2
Regulatory assets, non-current:
Pension benefits	B	Ongoing	$	91.6	$	99.6
Deferred recoverable income taxes	B/C	Ongoing	36.4		43.1
Fuel costs	B	Undetermined	12.7		—
Unrecovered OVEC charges	D	Undetermined	10.5		—
Unamortized loss on reacquired debt	B	Various	9.0		9.9
Smart grid and advanced metering infrastructure costs	D	Undetermined	7.3		6.6
Generation separation costs	D	Undetermined	3.9		1.6
Retail settlement system costs	D	Undetermined	3.1		3.1
Consumer education campaign	D	Undetermined	3.0		3.0
Rate case costs	D	Undetermined	1.9		—
Other miscellaneous	D	Undetermined	0.5		0.6
Total regulatory assets, non-current			179.9		167.5
Total regulatory assets			$	194.3	$	211.7
Regulatory liabilities, current:
Energy efficiency program			$	9.2	$	—
Competitive bidding			9.1		—
Transmission costs			3.7		2.9
Reconciliation rider			2.1		—
Other miscellaneous			0.3		1.5
Total regulatory liabilities, current			24.4		4.4
Regulatory liabilities, non-current:
Estimated costs of removal - regulated property			$	121.8	$	119.3
Postretirement benefits			5.2		4.8
Total regulatory liabilities, non-current			127.0		124.1
Total regulatory liabilities			$	151.4	$	128.5

A – Recovery of incurred costs without a rate of return.

B – Recovery of incurred costs plus rate of return.

C – Balance has an offsetting liability resulting in no effect on rate base.

D – Recovery not yet determined, but is probable of occurring in future rate proceedings.

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Regulatory assets

Fuel and purchased power recovery costsrepresent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider. The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. As part of the PUCO approval process, an outside auditor reviews fuel costs and the fuel procurement process. The audit for 2014 is in process. The costs recovered through the fuel rider have decreased significantly over the past three years as more SSO supply is provided through the competitive bid. While no further fuel or purchased power costs will be recoverable through the rider, it will continue for up to six months to allow for recovery of the ending deferral amount.

Fuel costs - long-term represent unrecovered fuel costs related to DP&L’s fuel rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.

Economic development costs represent costs incurred to promote economic development within the State of Ohio. These costs are being recovered through an Economic Development Rider that is subject to a bi-annual true-up process for any over/under recovery of costs.

Deferred storm costs represent costs incurred to repair the damage to DP&L’s distribution equipment by major storms in 2008, 2011 and 2012. All such costs have now been recovered.

Energy efficiency program costsrepresent costs incurred to develop and implement various customer programs addressing energy efficiency. These costs are being recovered through an Energy Efficiency Rider (EER) that began July 1, 2009 and that is subject to an annual true-up for any over/under recovery of costs. In addition to recovery of program costs, this rider has allowed for DP&L to recover lost margin associated with decreases in sales as a result of the programs implemented. The authority to recover lost margin included a maximum amount, which DP&L reached in the fourth quarter of 2015. Consequently, we discontinued accruing an asset for lost revenues after the maximum was reached. In addition, this rider provides that DP&L can earn a “shared savings” incentive that is tiered depending upon the level of success the programs reach. In 2014 and 2015, the maximum shared savings was accrued based upon performance, which is equal to $4.5 million per year, after income taxes.

Pension benefitsrepresent the qualifying FASC 715 “Compensation - Retirement Benefits” costs of our regulated operations that for ratemaking purposes are deferred for future recovery. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory asset represents the regulated portion that would otherwise be charged as a loss to OCI.

Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow-through items as the result of tax benefits previously provided to customers. This is the cumulative flow-through benefit given to regulated customers that will be collected from them in future years. Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, these deferred recoverable income taxes will decrease over time.

Unrecovered OVEC charges represent the portion of capacity charges from OVEC that were not recoverable through DP&L’s fuel rider beginning in October 2014. DP&L expects to recover these costs through a future rate proceeding.

Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with FERC and PUCO rules.

Smart Grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and the implementation of AMI. On October 19, 2010, DP&L elected to withdraw its case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities' Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. This plan is currently under development and we plan

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to seek recover of these deferred costs in a regulatory rate proceeding in the near future. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates.

Generation separation costs represent financing, redemption and other costs related to the divestiture of DP&L’s generation assets. The PUCO directed DP&L to divest its generation assets by January 1, 2017. DP&L requested and was granted permission by the PUCO to defer all financing, redemption and related costs it incurs to transfer its generation assets. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.

Retail settlement system costsrepresent costs to implement a retail settlement system that reconciles the energy a CRES supplier delivers to its customers with what its customers actually use. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.

Consumer education campaignrepresents costs for consumer education advertising regarding electric deregulation. DP&L has requested recovery of these costs as part of its pending distribution rate case filing.

Rate case costs represent costs associated with preparing a distribution rate case. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.

Regulatory liabilities

Energy efficiency program costs see “Regulatory Assets - Energy efficiency program costs” above.

Competitive bidding represents costs associated with the development and implementation of a Competitive Bidding Process, establishing contracts to supply power for a portion of DP&L’s Standard Service Offer load, as well as the net over/under recovery of the cost of the power purchased from the bid winners.

Transmission costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM. On an annual basis, retail rates are adjusted to true-up costs with recovery in rates.

Reconciliation rider represents the costs that exceed 10 percent of the base amount of the following riders: Fuel, RPM, Alternative Energy and Competitive Bidding. This rider is in an overcollection position and will be discontinued after this overcollection has been refunded to customers.

Estimated costs of removal – regulated property reflect an estimate of amounts collected in customer rates for costs that are expected to be incurred in the future to remove existing transmission and distribution property from service when the property is retired.

Postretirement benefits represent the qualifying FASC 715 “Compensation – Retirement Benefits” gains related to our regulated operations that, for ratemaking purposes, are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be reflected as a gain to OCI.

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Note 4 – Property, Plant and Equipment

The following is a summary of DPL’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2015 and 2014:

	December 31,
$ in millions	2015		Composite Rate	2014		Composite Rate
Regulated:
Transmission	$	239.4	3.9%	$	227.5	4.1%
Distribution	1,085.7		5.0%	1,011.7		5.4%
General	65.9		12.4%	62.5		12.4%
Non-depreciable	62.5		N/A	61.6		N/A
Total regulated	1,453.5			1,363.3
Unregulated:
Production / Generation	1,418.7		4.2%	1,354.9		5.4%
Other	17.0		8.1%	16.1		5.5%
Non-depreciable	19.8		N/A	19.8		N/A
Total unregulated	1,455.5			1,390.8
Total property, plant and equipment in service	$	2,909.0	4.6%	$	2,754.1	5.3%

DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. At December 31, 2015, DP&L had $39.0 million of construction work in process at such facilities. DP&L’s share of the operations of such facilities is included within the corresponding line in the 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 Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.

Coal-fired facilities

DP&L’s undivided ownership interest in such facilities at December 31, 2015, is as follows:

	DP&L Share		DPL Carrying Value
	Ownership (%)	Summer Production Capacity (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)
Jointly-owned production units
Conesville - Unit 4	16.5	129	$	26	$	4	$	1
Killen - Unit 2	67.0	402	342		29		2
Miami Fort - Units 7 and 8	36.0	368	219		32		6
Stuart - Units 1 through 4	35.0	808	236		19		18
Zimmer - Unit 1	28.1	371	188		44		12
Transmission (at varying percentages)			43		8		—
Total		2,078	$	1,054	$	136	$	39

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

Beckjord Unit 6 was retired effective October 1, 2014, and DP&L’s sale of its interest in East Bend closed on December 30, 2014.

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. Our generation AROs are recorded within Other deferred credits on the consolidated balance sheets.

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 December 31, 2013	$	24.4
Calendar 2014
Additions	3.6
Accretion expense	0.9
Settlements	(2.0		)
Balance at December 31, 2014	26.9
Calendar 2015
Additions	40.3
Accretion expense	1.9
Settlements	(3.2		)
Balance at December 31, 2015	$	65.9

Asset Removal Costs

We continue to record costs of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $121.8 million and $119.3 million in estimated costs of removal at December 31, 2015 and 2014, respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 3 – Regulatory Assets and Liabilities for additional information.

Changes in the Liability for Transmission and Distribution Asset Removal Costs

$ in millions
Balance at December 31, 2013	$	115.0
Calendar 2014
Additions	19.6
Settlements	(15.3		)
Balance at December 31, 2014	119.3
Calendar 2015
Additions	24.3
Settlements	(21.8		)
Balance at December 31, 2015	$	121.8

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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 method is available to us. The fair value of our financial instruments represents estimates of possible value that may or may not be realized in the future.

The table below presents the fair value and cost of our non-derivative instruments at December 31, 2015 and 2014. See Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments.

	December 31, 2015				December 31, 2014
$ in millions	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets
Money market funds	$	0.2	$	0.2	$	0.1	$	0.1
Equity securities	3.0		3.8		2.7		3.7
Debt securities	4.4		4.3		4.7		4.7
Hedge Funds	0.4		0.4		0.8		0.8
Real Estate	0.3		0.3		0.4		0.4
Total assets	$	8.3	$	9.0	$	8.7	$	9.7
Liabilities
Debt	$	2,009.4	$	1,975.3	$	2,159.7	$	2,204.8

Fair value hierarchy

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

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

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

• Level 3 (unobservable inputs).

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

We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy during the twelve months ended December 31, 2015 and 2014.

Debt

The fair value of debt is based on current public market prices for disclosure purposes only. Unrealized gains or losses are not recognized in the financial statements as debt is presented at the carrying value, net of unamortized premium or discount, in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2016 to 2061.

Master trust assets

DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.

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DPL had $0.7 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, and $0.8 million ($0.5 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2014.

Various investments were sold during the past twelve months to facilitate the distribution of benefits. During the past twelve months, an immaterial amount of unrealized gains were reversed into earnings. Over the next twelve months, an immaterial amount of unrealized gains is expected to be reversed to earnings.

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

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2015 (a)		Based on Quoted Prices in Active Markets		Other observable inputs		Unobservable inputs
Assets
Master trust assets
Money market funds	$	0.2	$	0.2	$	—	$	—
Equity securities	3.8		—		3.8		—
Debt securities	4.3		—		4.3		—
Hedge Funds	0.4		—		0.4		—
Real Estate	0.3		—		0.3		—
Total Master trust assets	9.0		0.2		8.8		—
Derivative assets
Forward power contracts	30.5		—		30.5		—
FTRs	0.2		—		—		0.2
Total Derivative assets	$	30.7	$	—	$	30.5	$	0.2
Total assets	$	39.7	$	0.2	$	39.3	$	0.2
Liabilities
FTRs	0.5		$	—	$	—	$	0.5
Forward power contracts	27.0		—		23.9		3.1
Total derivative liabilities	27.5		—		23.9		3.6
Long-term debt	1,975.3		—		1,957.2		18.1
Total liabilities	$	2,002.8	$	—	$	1,981.1	$	21.7

(a) Includes credit valuation adjustment.

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The fair value of assets and liabilities at December 31, 2014 and the respective category within the fair value hierarchy for DPL was determined as follows:

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2014 (a)		Based on Quoted Prices in Active Markets		Other observable inputs		Unobservable inputs
Assets
Master trust assets
Money market funds	$	0.1	$	0.1	$	—	$	—
Equity securities	3.7		3.7		—		—
Debt securities	4.7		4.7		—		—
Hedge Funds	0.8		—		0.8		—
Real Estate	0.4		0.4		—		—
Total Master trust assets	9.7		8.9		0.8		—
Derivative assets
Forward power contracts	14.9		—		13.7		1.2
Total derivative assets	14.9		—		13.7		1.2
Total assets	$	24.6	$	8.9	$	14.5	$	1.2
Liabilities
FTRs	$	0.6	$	—	$	—	$	0.6
Heating oil futures	0.4		0.4		—		—
Natural gas futures	0.1		0.1		—		—
Forward power contracts	11.1		—		11.1		—
Total derivative liabilities	12.2		0.5		11.1		0.6
Long-term debt	2,204.8		—		2,186.6		18.2
Total liabilities	$	2,217.0	$	0.5	$	2,197.7	$	18.8

(a) Includes credit valuation adjustment.

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

• Level 1 inputs are used for derivative contracts, such as heating oil 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 the end of day NAV per unit.

• Level 3 inputs, such as financial transmission rights, are considered a Level 3 input because the monthly auctions are considered inactive. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.

Our debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. The WPAFB note is not publicly traded. Fair value is assumed to equal carrying value. These fair value inputs are considered

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Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures were not presented since debt is not recorded at fair value.

Approximately 99% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Non-recurring Fair Value Measurements

We use the cost approach to determine the fair value of our AROs, which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. AROs for asbestos, ash ponds, underground storage tanks, and river structures increased by a net amount of $39.0 million ($25.4 million after tax) and $2.5 million ($1.6 million after tax) during the 12 months endedDecember 31, 2015 and 2014, respectively. The majority of the increase for 2015 is due to a net increase in the ARO for ash ponds of $40.3 million ($26.2 million after tax) as a result of new rules promulgated by the USEPA that were published in the Federal Register in April 2015 and became effective in October 2015. See Note 4 – Property, Plant and Equipment for more information about AROs.

When evaluating impairment of goodwill and 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 major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:

$ in millions	Year ended December 31, 2015
	Carrying		Fair Value						Gross
	Amount		Level 1		Level 2		Level 3		Loss
Goodwill(b)
DP&L reporting unit	$	317.0	$	—	$	—	$	—	$	317.0

$ in millions	Year ended December 31, 2014
	Carrying		Fair Value						Gross
	Amount		Level 1		Level 2		Level 3		Loss
Assets
Long-lived assets held and used (a)
DP&L (East Bend)	$	14.2	$	—	$	—	$	2.7	$	11.5
Goodwill (b)
DPLER Reporting unit	$	135.8	$	—	$	—	$	—	$	135.8

$ in millions	Year ended December 31, 2013
	Carrying		Fair Value						Gross
	Amount		Level 1		Level 2		Level 3		Loss
Assets
Long-lived assets held and used (a)
DP&L (Conesville)	$	26.2	$	—	$	—	$	—	$	26.2
Goodwill (b)
DP&L Reporting unit	$	623.3	$	—	$	—	$	317.0	$	306.3

(a) See Note 15 – Fixed-asset Impairment for further information

(b) See Note 7 – Goodwill and Other Intangible Assets for further information

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Note 6 – Derivative Instruments and Hedging Activities

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

At December 31, 2015, DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment	Unit	Purchases (in thousands)	Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	10.2	—		10.2
Forward Power Contracts	Designated	MWh	1,676.7	(7,795.8	)	(6,119.1	)
Forward Power Contracts	Not designated	MWh	5,049.9	(1,663.0	)	3,386.9

At December 31, 2014, DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment	Unit	Purchases (in thousands)	Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	10.5	—		10.5
Heating Oil Futures	Not designated	Gallons	378.0	—		378.0
Natural Gas Futures	Not designated	Dths	200.0	—		200.0
Forward Power Contracts	Designated	MWh	175.0	(2,991.0	)	(2,816.0	)
Forward Power Contracts	Not designated	MWh	1,725.2	(2,707.8	)	(982.6	)

Cash flow hedges

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

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

We also 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. We do not hedge all interest rate exposure. We reclassify gains and losses on interest rate derivative hedges out of AOCI and into earnings in those periods in which hedged interest payments occur.

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The following tables set forth the gains / (losses) recognized in AOCI and earnings related to the effective portion of derivative instruments and the gains / (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the periods indicated:

	Years ended December 31,
	2015						2014						2013
$ in millions (net of tax)	Power			Interest Rate Hedges			Power			Interest Rate Hedges			Power			Interest Rate Hedges
Beginning accumulated derivative gain / (loss) in AOCI	$	0.2		$	18.3		$	1.4		$	19.2		$	(3.0	)	$	0.5
Net gains / (losses) associated with current period hedging transactions	18.2			—			(19.0		)	—			1.0			18.7
Net gains / (losses) reclassified to earnings:
Interest Expense	—			(0.8		)	—			(0.9		)	—			—
Revenues	(12.0		)	—			18.3			—			2.1			—
Purchased Power	2.8			—			(0.5		)	—			1.3			—
Ending accumulated derivative gain in AOCI	$	9.2		$	17.5		$	0.2		$	18.3		$	1.4		$	19.2
Net gains / (losses) associated with the ineffective portion of the hedging transaction
Interest Expense	$	—		$	—		$	—		$	—		$	—		$	0.8
Portion expected to be reclassified to earnings in the next twelve months (a)	$	5.9		$	(0.8	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	36			—

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

Derivatives not designated as hedges

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchases and sales exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the consolidated statements of results 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. We mark to market FTRs, heating oil futures and certain forward power contracts.

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

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Regulatory assets and liabilities

In accordance with regulatory accounting under GAAP, a cost that is probable of recovery in future rates should be deferred as a regulatory asset and a gain that is probable of being returned to customers should be deferred as a regulatory liability. Portions of the derivative contracts that are marked to market each reporting period and are related to the retail portion of DP&L’s load requirements are included as part of the fuel and purchased power recovery rider approved by the PUCO which began January 1, 2010. Therefore, the Ohio retail customers’ portion of the heating oil futures are 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.

The following tables show the amount and classification within the consolidated statements of results of operations or balance sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the years ended December 31, 2015, 2014 and 2013:

	Year ended December 31, 2015
$ in millions	Heating Oil			FTRs			Power			Natural Gas			Total
Derivatives not designated as hedging instruments
Change in unrealized loss	$	0.4		$	0.3		$	(6.4	)	$	0.1		$	(5.6	)
Realized gain / (loss)	(0.3		)	(0.2		)	(9.8		)	(0.1		)	(10.4		)
Total	$	0.1		$	0.1		$	(16.2	)	$	—		$	(16.0	)
Recorded on Balance Sheet:
Regulatory asset	$	0.1		$	—		$	—		$	—		$	0.1
Recorded in Income Statement: gain / (loss)
Purchased Power	—			0.1			(43.6		)	—			(43.5		)
Revenue	—			—			27.4			—			27.4
Total	$	0.1		$	0.1		$	(16.2	)	$	—		$	(16.0	)

	Year ended December 31, 2014
$ in millions	Heating Oil			FTRs			Power			Natural Gas			Total
Derivatives not designated as hedging instruments
Change in unrealized gain	$	(0.6	)	$	(0.8	)	$	(1.5	)	$	(0.1	)	$	(3.0	)
Realized gain	(0.1		)	0.7			(3.6		)	(0.1		)	(3.1		)
Total	$	(0.7	)	$	(0.1	)	$	(5.1	)	$	(0.2	)	$	(6.1	)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1	)	$	—		$	—		$	—		$	(0.1	)
Recorded in Income Statement: gain / (loss)
Purchased Power	—			(0.1		)	(5.1		)	(0.2		)	(5.4		)
Fuel	(0.6		)	—			—			—			(0.6		)
Total	$	(0.7	)	$	(0.1	)	$	(5.1	)	$	(0.2	)	$	(6.1	)

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	Year ended December 31, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Derivatives not designated as hedging instruments
Change in unrealized gain / (loss)	$	—	$	0.3	$	0.6	$	0.9
Realized gain / (loss)	0.1		1.2		1.1		2.4
Total	$	0.1	$	1.5	$	1.7	$	3.3
Recorded in Income Statement: gain / (loss)
Revenue	—		—		—		—
Purchased Power	—		1.5		1.7		3.2
Fuel	0.1		—		—		0.1
O&M	—		—		—		—
Total	$	0.1	$	1.5	$	1.7	$	3.3

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The following tables show the fair value, balance sheet classification and hedging designation of DPL’s derivative instruments at December 31, 2015 and 2014.

Fair Values of Derivative Instruments
December 31, 2015
				Gross Amounts Not Offset in the Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Consolidated Balance Sheets (a)		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Designated	$	16.2	$	(7.1	)	$	—		$	9.1
Forward power contracts	Not designated	7.3		(5.5		)	—			1.8
FTRs	Not designated	0.2		(0.2		)	—			—
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	3.0		(2.4		)	—			0.6
Forward power contracts	Not designated	4.0		(2.7		)	—			1.3
Total assets		$	30.7	$	(17.9	)	$	—		$	12.8
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	7.1	$	(7.1	)	$	—		$	—
Forward power contracts	Not designated	14.5		(5.5		)	(8.0		)	1.0
FTRs	Not designated	0.5		(0.2		)	—			0.3
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Designated	2.7		(2.4		)	—			0.3
Forward power contracts	Not designated	2.7		(2.7		)	—			—
Total liabilities		$	27.5	$	(17.9	)	$	(8.0	)	$	1.6

(a) Includes credit valuation adjustment.

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Fair Values of Derivative Instruments
December 31, 2014
				Gross Amounts Not Offset in the Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Consolidated Balance Sheets (a)		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Designated	$	5.6	$	(2.0	)	$	—		$	3.6
Forward power contracts	Not designated	5.5		(3.4		)	—			2.1
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	0.3		(0.3		)	—			—
Forward power contracts	Not designated	3.5		(0.9		)	—			2.6
Total assets		$	14.9	$	(6.6	)	$	—		$	8.3
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	2.1	$	(2.0	)	$	—		$	0.1
Forward power contracts	Not designated	7.5		(3.4		)	(4.1		)	—
FTRs	Not designated	0.6		—			—			0.6
Heating Oil Futures	Not designated	0.4		—			(0.4		)	—
Natural Gas	Not designated	0.1		—			(0.1		)	—
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Designated	0.6		(0.3		)	(0.3		)	—
Forward power contracts	Not designated	0.9		(0.9		)	—			—
Total liabilities		$	12.2	$	(6.6	)	$	(4.9	)	$	0.7

(a) Includes credit valuation adjustment.

As of December 31, 2014, the above table includes Forward power contracts in a short-term asset position of $11.1 million. This table does not include a short-term asset position of $0.1 million of Forward power contracts that had been, but no longer need to be, accounted for as derivatives at fair value that are to be amortized to earnings over the remaining term of the associated forward contract.

Credit risk-related contingent features

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies. Since our debt has fallen below investment grade, we are in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization of the MTM loss. Some of our counterparties to the derivative instruments have requested collateralization of the MTM loss.

The aggregate fair value of DPL’s derivative instruments that are in a MTM loss position at December 31, 2015 is $27.5 million. This amount is offset by $8.0 million of collateral 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 $17.9 million. Since our debt is below investment grade, we could have to post collateral for the remaining $1.6 million.

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Note 7 – Goodwill and Other Intangible Assets

Goodwill

The following table summarizes the changes in Goodwill by reportable segment for the years ended December 31, 2015, 2014 and 2013:

$ in millions	DP&L Reporting Unit			DPLER Reporting Unit			Total
Balance at December 31, 2013
Goodwill	$	2,440.5		$	135.8		$	2,576.3
Accumulated impairment losses	(2,123.5		)	—			(2,123.5		)
Net balance at December 31, 2013	$	317.0		$	135.8		$	452.8
Goodwill impairments during 2014	$	—		$	(135.8	)	$	(135.8	)
Balance at December 31, 2014
Goodwill	$	2,440.5		$	135.8		$	2,576.3
Accumulated impairment losses	(2,123.5		)	(135.8		)	(2,259.3		)
Net balance at December 31, 2014	$	317.0		$	—		$	317.0
Goodwill impairments during 2015	$	(317.0	)	$	—		$	(317.0	)
Balance at December 31, 2015
Goodwill	$	2,440.5		$	135.8		$	2,576.3
Accumulated impairment losses	(2,440.5		)	(135.8		)	(2,576.3		)
Net balance at December 31, 2015	$	—		$	—		$	—

In connection with the acquisition of DPL by AES, DPL allocated the purchase price to goodwill for two reporting units, the DP&L reporting unit, which included DP&L and other entities, and DPLER. Of the total goodwill, approximately $2.4 billion was allocated to the DP&L reporting unit and the remainder was allocated to DPLER. Goodwill represented the value assigned at the Merger date, as adjusted for subsequent changes in the purchase price allocation, less recognized impairments.

DPLER Reporting Unit

During the first quarter of 2014, we performed an interim impairment test on the $135.8 million in goodwill at our DPLER reporting unit. During the second quarter of 2014, we finalized the work to determine the implied fair value for the DPLER reporting unit. There were no further adjustments to the full impairment of $135.8 million recognized in the first quarter. DPLER was sold on January 1, 2016 and is presented in discontinued operations on the Consolidated Statement of Operations. See Note 16 – Discontinued Operations for additional information.

DP&L Reporting Unit

During the fourth quarter of 2015, DPL performed its annual goodwill impairment test and recognized a goodwill impairment at its DP&L reporting unit of $317.0 million. The reporting unit failed Step 1 as its fair value was less than its carrying amount, which was primarily due to a decrease forecasted in dark spreads that were driven by decreases in projected forward power prices, and lower than expected revenues from the CP product. The fair value of the reporting unit was determined under the income approach using a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were forward commodity price curves, expected revenues from the new CP product, and planned environmental expenditures. In Step 2, goodwill was determined to have no implied fair value after the hypothetical purchase price allocation under the accounting guidance for business combinations; therefore, a full impairment of the remaining goodwill balance of $317.0 million was recognized. The goodwill associated with the Merger is not deductible for tax purposes. Accordingly, there is no financial statement tax benefit related to the impairment.

During the fourth quarter of 2013, DPL performed its annual goodwill impairment test and recognized a goodwill impairment at its DP&L reporting unit of $306.3 million. In performing the annual goodwill impairment test as of October 1, 2013, Step 1 of the test failed as the fair value of the reporting unit no longer exceeded its carrying amount due primarily to lower estimates of capacity prices in future years as well as lower dark spreads contributing

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to lower overall operating margins for the business. The fair value of the reporting unit was determined under the income approach using a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were capacity price curves, amount of the non-bypassable charge, commodity price curves, dispatching, valuation of regulatory assets and liabilities, discount rates and deferred income taxes. In Step 2, goodwill was determined to have an implied fair value of $317.0 million after the hypothetical purchase price allocation under the accounting guidance for business combinations.

The goodwill associated with the Merger is not deductible for tax purposes. Accordingly, there is no cash or financial statement tax benefit related to the impairment.

Note 8 – Debt

Long-term debt
$ in millions	Interest Rate	Maturity	December 31, 2015			December 31, 2014
First mortgage bonds	1.875%	2016	$	445.0		$	445.0
Pollution control series	4.7%	2028	—			35.3
Pollution control series	4.8%	2034	—			179.1
Pollution control series	4.8%	2036	100.0			100.0
Pollution control series - rates from: 0.02% - 0.12% and 0.04% - 0.15% (a)		2040	—			100.0
Pollution control series - rates from: 1.13% - 1.17%		2020	200.0			—
U.S. Government note	4.2%	2061	18.1			18.2
Unamortized debt discounts and premiums, net			(3.6		)	(2.8		)
Total long-term debt at subsidiary			759.5			874.8
Bank term loan - rates from: 2.44% - 2.67% and 2.41% - 2.44% (a)		2020	125.0			160.0
Senior unsecured bonds	6.5%	2016	130.0			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 (b)	8.125%	2031	15.6			15.6
Unamortized debt discounts and premiums, net			(0.7		)	(0.7		)
Subtotal			$	2,009.4		$	2,159.7
Less: current portion			(574.9		)	(20.1		)
Total			1,434.5			2,139.6

(a) Range of interest rates for the years ended December 31, 2015 and 2014, respectively.

(b) Note payable to related party. See Note 13 – Related Party Transactions for additional information.

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At December 31, 2015, maturities of long-term debt are summarized as follows:

Due within the years ending December 31,
$ in millions
2016	$	575.1
2017	25.1
2018	25.1
2019	225.2
2020	250.2
Thereafter	913.0
	2,013.7
Unamortized discounts and premiums, net	(4.3		)
Total long-term debt	$	2,009.4

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

Significant transactions

On July 1, 2015, the $35.3 million of DP&L's4.7% pollution control bonds due January 2028 and $41.3 million of DP&L's4.8% pollution control bonds due January of 2034 were called at par and were redeemed with cash.

On July 31, 2015, DP&L refinanced its revolving credit facility. The new facility has a $175.0 million borrowing limit, with a $50.0 million letter of credit sublimit, a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million and maturity date of July 2020. At December 31, 2015, there were two letters of credit in the amount of $1.4 million outstanding, with the remaining $173.6 million available to DP&L. Fees associated with this revolving credit facility were not material during the years ended December 31, 2015 or 2014. Prior to refinancing the facility on July 31, 2015, this facility had a $300.0 million borrowing limit, a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provided DP&L the ability to increase the size of the facility by an additional $100.0 million.

On August 3, 2015, DP&L called $100.0 million of variable rate pollution control bonds due November 2040, terminated the amended standby letter of credit facilities that supported these pollution control bonds, and called $137.8 million of 4.8% pollution control bonds due January of 2034. DP&L also used cash to redeem $37.8 million of these bonds and refinanced the $200.0 million balance, with new variable interest rate pollution control bonds secured by first mortgage bonds in an equivalent amount. In connection with the sale of the new pollution control bonds, DP&L entered into a certain Bond Purchase and Covenants Agreement, dated as of August 1, 2015, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L.

On September 19, 2013, DP&L closed a $445.0 million issuance of senior secured first mortgage bonds. These new bonds mature on September 15, 2016, and are secured by DP&L’s First & Refunding Mortgage. Substantially all property, plant and equipment of DP&L is subject to the lien of the First and Refunding Mortgage. Substantially concurrent with this transaction, DP&L redeemed $470.0 million of previously outstanding first mortgage bonds.

On July 31, 2015, DPL refinanced its revolving credit facility. The new facility has a total size of $205.0 million, a $200.0 million letter of credit sublimit, a feature that provides DPL the ability, under certain circumstances, to increase the size of the facility by an additional $95.0 million and a maturity date of July 2020. DPL's new credit facility also 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. 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 DPLE secured by mortgages on assets of DPLE. At December 31, 2015, there were two letters of credit in the amount of $3.0 million outstanding under this facility, with the remaining

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$202.0 million of the revolving credit facility remaining available to DPL. Fees associated with this facility were not material during the years ended December 31, 2015 or 2014.

Prior to refinancing the facility on July 31, 2015, this facility was unsecured and had a borrowing limit of $100.0 million with a $100.0 million letter of credit sublimit, was able to be increased in size by DPL by an additional $50.0 million and had a five-year term expiring on May 10, 2018; with a springing maturity, meaning that if DPL had not refinanced its senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this facility would have been July 15, 2016.

Also on July 31, 2015, DPL refinanced its term loan, paying down the outstanding amount of $160.0 million using proceeds from the new term loan of $125.0 million and a combination of cash on hand and draws on short term credit facilities. The new term loan extends the term to July of 2020, pushing back required principal payments to 2017, and providing a mechanism for DPL to request additional term loans to refinance existing indebtedness. The new term loan 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. 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 DPLE secured by mortgages on assets of DPLE. The new term loan 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.

In October 2014, DPL repaid $5.0 million of the note due to Capital Trust II, which used the funds to repurchase securities in the open market at a slight premium. Subsequent to repurchasing these securities, Capital Trust II immediately retired them.

In connection with the closing of the Merger, DPL assumed $1,250.0 million of debt that Dolphin Subsidiary II, Inc., a subsidiary of AES, issued on October 3, 2011 to partially finance the Merger. The $1,250.0 million was issued in two tranches. The first tranche was $450.0 million of five year senior unsecured notes issued with a 6.50% coupon maturing on October 15, 2016. The second tranche was $800.0 million of ten year senior unsecured notes issued with a 7.25% coupon maturing on October 15, 2021. In December 2013, DPL executed an Open Market Repurchase Program and successfully bought back $20.0 million of both the first and second tranche of senior unsecured notes andimmediately retired them.

In October 2014, DPL closed a $200.0 million issuance of senior unsecured bonds. These new bonds were priced at 6.75% and mature on October 1, 2019. Proceeds from the issuance, in addition to a draw on the DPL revolving line of credit and cash on hand, were used to settle a tender offer for $300.0 million of the 6.50% senior unsecured notes maturing October 15, 2016. After this transaction, the DPL Inc. 6.5% Senior Notes due 2016 had an outstanding principle balance of $130.0 million

On January 6, 2016, DPL issued a Notice of Partial Redemption to the Trustee (Wells Fargo Bank N.A.) on the DPL Inc. 6.5% Senior Notes due 2016 (a component of the Dolphin Subsidiary II, Inc. debt). DPL notified the trustee that it was calling $73.0 million of the $130.0 million outstanding principal amount of these notes. The record date of this redemption was January 21, 2016, and the redemption date was February 5, 2016. These bonds were redeemed at par plus accrued interest and a make-whole premium of $2.4 million.

Debt covenants and restrictions

DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement (financing document entered into in connection with the sale of the new $200.0 million of variable rate pollution control bonds, dated as of August 1, 2015, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L) have two financial covenants. The first measures Total Debt to Total Capitalization and is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.

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

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quarter by consolidated EBITDA for the four prior fiscal quarters. The second financial covenant is an EBITDA to Interest Expense ratio that is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.

As of December 31, 2015, DP&L and DPL were in compliance with all debt covenants, including the financial covenants described above.

DP&L doesnot have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL. DPL’s secured revolving credit agreement, secured term loan, and senior unsecured notes due 2019 restrict dividend payments from DPL to AES, such that DPL cannot make dividend payments unless at the time of, and/or as a result of, the distribution, DPL’s leverage ratio does not exceed 0.67 to 1.00 and DPL’s interest coverage ratio is not less than 2.50 to 1.00 or, if such ratios are not within the parameters, DPL’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. Further, the restrictions on the payment of distributions to a shareholder cease to be in effect if the three major credit rating agencies confirm that a lowering of DPL’s senior long-term debt rating below investment grade by the credit rating agencies would not occur without these restrictions. As of December 31, 2015, DPL’s leverage ratio was at 1.03 to 1.00 and DPL’s senior long-term debt rating from all three major credit rating agencies was below investment grade. As a result, as of December 31, 2015, DPL was prohibited under each of these agreements from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).

Note 9 – Income Taxes

DPL’s components of income tax expense on continuing operations were as follows:

	Years ended December 31,
$ in millions	2015			2014			2013
Computation of tax expense
Federal income tax expense / (benefit)(a)	$	(81.0	)	$	25.4		$	(71.7	)
Increases (decreases) in tax resulting from:
State income taxes, net of federal effect	(0.1		)	0.8			1.1
Depreciation of AFUDC - Equity	(3.5		)	(3.4		)	(3.2		)
Investment tax credit amortized	(0.5		)	(0.5		)	(0.5		)
Section 199 - domestic production deduction	(4.1		)	(1.1		)	(4.1		)
Non-deductible goodwill impairment	111.0			—			107.2
Accrual (settlement) for open tax years	—			(6.6		)	(8.8		)
Other, net (b)	(1.8		)	0.8			(0.2		)
Total tax expense	$	20.0		$	15.4		$	19.8
Components of tax expense
Federal - current	$	30.1		$	(5.2	)	$	(2.5	)
State and Local - current	0.8			0.4			—
Total current	30.9			(4.8		)	(2.5		)
Federal - deferred	(9.9		)	19.6			20.6
State and local - deferred	(1.0		)	0.6			1.7
Total deferred	(10.9		)	20.2			22.3
Total tax expense	$	20.0		$	15.4		$	19.8

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Effective and Statutory Rate Reconciliation

The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to DPL's effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 2015, 2014 and 2013:

	Years ended December 31,
	2015		2014		2013
Statutory Federal tax rate	35.0	%	35.0	%	35.0	%
State taxes, net of Federal tax benefit	0.1	%	1.1	%	(0.6	)%
AFUDC - Equity	1.5	%	(4.7	)%	1.5	%
Amortization of investment tax credits	0.2	%	(0.7	)%	0.2	%
Section 199 - domestic production deduction	1.8	%	(1.6	)%	2.0	%
Non-deductible goodwill impairment	(48.0	)%	—	%	(52.1	)%
Other, net	0.8	%	(7.9	)%	4.3	%
Effective tax rate	(8.6	)%	21.2	%	(9.7	)%

Deferred Income Taxes

Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.

Components of Deferred Tax Assets and Liabilities
	December 31,
$ in millions	2015			2014
Net non-current Assets / (Liabilities)
Depreciation / property basis	$	(539.8	)	$	(548.2	)
Income taxes recoverable	(12.0		)	(14.8		)
Regulatory assets	(10.6		)	(18.0		)
Investment tax credit	0.7			1.5
Compensation and employee benefits	3.1			3.2
Intangibles	(8.4		)	(7.0		)
Long-term debt	(1.1		)	(1.5		)
Other (c)	(0.6		)	(2.5		)
Net non-current liabilities	$	(568.7	)	$	(587.3	)
Net current Assets / (Liabilities)(d)
Other	$	—		$	1.1
Net current assets / (liabilities)	$	—		$	1.1

(a) The statutory tax rate of 35% was applied to pre-tax earnings.

(b) Includes expense of $0.2 million, $0.4 million and $0.0 million in the years ended December 31, 2015, 2014, and 2013, respectively, of income tax related to adjustments from prior years.

(c) The Other non-current liabilities caption includes deferred tax assets of $26.0 million in 2015 and $27.1 million in 2014 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $17.2 million in 2015 and $18.9 million in 2014. These net operating loss carryforwards expire from 2016 to 2030.

(d) Amounts are included within Other prepayments and current assets and Other current liabilities on the Consolidated Balance Sheet of DPL at December 31, 2014.

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The following table presents the tax expense / (benefit) related to pensions, postemployment benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss.

	Years ended December 31,
$ in millions	2015		2014			2013
Tax expense / (benefit)	$	6.3	$	(9.1	)	$	15.4

Uncertain Tax Positions

We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

$ in millions
Balance at December 31, 2013	$	8.8
Calendar 2014
Tax positions taken during prior period	2.8
Lapse of Statute of Limitations	(8.6		)
Balance at December 31, 2014	3.0
Calendar 2015
Tax positions taken during prior period	—
Lapse of Statute of Limitations	—
Balance at December 31, 2015	$	3.0

Of the December 31, 2015 balance of unrecognized tax benefits, $0.9 million is due to uncertainty in the timing of deductibility.

We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The amounts accrued as well as the expense / (benefit) recorded were not material for the years ended December 31, 2015, 2014 and 2013.

Following is a summary of the tax years open to examination by major tax jurisdiction:

U.S. Federal – 2010 and forward

State and Local – 2010 and forward

None of the unrecognized tax benefits are expected to significantly increase or decrease within the next twelve months other than those subject to expiring statute of limitations.

The Internal Revenue Service began an examination of our 2008 Federal income tax return during the second quarter of 2010. The results of the examination were approved by the Joint Committee on Taxation on January 18, 2013. As a result of the examination, DPL received a refund of $19.9 million and recorded a $1.2 million reduction to income tax expense in 2013.

Note 10 – Benefit Plans

Defined contribution plans

DP&L sponsors two defined contribution plans. One is for non-union employees (the management plan) and one is for collective bargaining employees (the union plan). Both plans are qualified under Section 401 of the Internal Revenue Code.

Certain non-union employees become eligible to participate in the management plan on the first day of the month following the first full calendar month of employment; provided the employee worked at least 160 hours in that calendar month. Union employees become eligible to participate in the union plan on the first day of the first month following 30 days of employment. Effective January 1, 2016, employees in both plans are eligible to participate upon date of hire.

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Participants may elect to contribute up to 85% of eligible compensation to their plan. Non-union participant contributions are matched 100% on the first 1% of eligible compensation and 50% on the next 5% of eligible compensation and they are fully vested in their employer contributions after 2 years of service. Union participant contributions are matched 150% but are capped at $2,100 for 2015 and they are fully vested in their employer contributions after 3 years of service. All participants are fully vested in their own contributions.

For the years ended December 31, 2015, 2014 and 2013, DP&L's contributions to all defined contribution plans were $4.8 million, $4.7 million and $4.8 million per year, respectively.

Defined benefit plans

DP&L sponsors a traditional defined benefit pension plan for most of the employees of DPL and its subsidiaries. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the traditional defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this traditional pension plan was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Effective January 1, 2014, the Service Company began providing services including 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. Employees that transferred from DP&L to the Service Company maintain their previous eligibility to participate in the DP&L pension plan.

Almost all management employees beginning employment on or after January 1, 2011 participate in a cash balance pension plan. Similar to the traditional pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment.

In addition, we have a Supplemental Executive Retirement Plan (SERP) for certain retired key executives. The SERP has an immaterial unfunded liability related to agreements for retirement benefits of certain terminated and retired key executives. We also include our net liability to our partners related to our share of their pension costs within Pension, retiree and other benefits on our Consolidated Balance Sheets.

We recognize an asset for a plan’s overfunded status and a liability for a plan’s underfunded status and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. For the transmission and distribution areas of our electric business, these amounts are recorded as regulatory assets and liabilities which represent the regulated portion that would otherwise be charged or credited to AOCI. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered through customer rates. This factor, combined with the historical precedents from the PUCO and FERC, make these costs probable of future rate recovery.

Postretirement benefits

Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from their retirement until they are covered by Medicare. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust.

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The following tables set forth the changes in our pension and postemployment benefit plans’ obligations and assets recorded on the balance sheets at December 31, 2015 and 2014. The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate. The amounts presented for postemployment obligations include both health and life insurance benefits.

$ in millions	Pension
	Years ended December 31,
	2015			2014
Change in benefit obligation
Benefit obligation at January 1	$	443.8		$	370.5
Service cost	7.1			5.9
Interest cost	17.3			17.5
Plan amendments	—			6.8
Actuarial (gain) / loss	(34.5		)	67.3
Benefits paid	(22.9		)	(24.2		)
Benefit obligation at December 31	410.8			443.8
Change in plan assets
Fair value of plan assets at January 1	371.7			349.1
Actual return on plan assets	(8.8		)	46.4
Contributions to plan assets	5.4			0.4
Benefits paid	(22.9		)	(24.2		)
Fair value of plan assets at December 31	345.4			371.7
Funded status of plan	$	(65.4	)	$	(72.1	)
	December 31,
Amounts recognized in the Balance sheets	2015			2014
Current liabilities	$	(0.4	)	$	(0.4	)
Non-current liabilities	(65.0		)	(71.7		)
Net liability at December 31,	$	(65.4	)	$	(72.1	)
Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
Components:
Prior service cost	$	12.0		$	14.1
Net actuarial loss	94.7			103.4
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax	$	106.7		$	117.5
Recorded as:
Regulatory asset	$	91.1		$	99.0
Regulatory liability	—			—
Accumulated other comprehensive income	15.6			18.5
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax	$	106.7		$	117.5

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$ in millions	Postretirement
	Years ended December 31,
	2015			2014
Change in benefit obligation
Benefit obligation at beginning of period	$	19.6		$	19.7
Service cost	0.2			0.2
Interest cost	0.6			0.8
Actuarial (gain) / loss	(1.1		)	0.2
Benefits paid	(1.5		)	(1.3		)
Benefit obligation at end of period	17.8			19.6
Change in plan assets
Fair value of plan assets at beginning of period	3.3			3.7
Contributions to plan assets	1.0			0.9
Benefits paid	(1.5		)	(1.3		)
Fair value of plan assets at end of period	2.8			3.3
Funded status of plan	$	(15.0	)	$	(16.3	)
	December 31,
	2015			2014
Amounts recognized in the Balance sheets
Current liabilities	$	(0.4	)	$	(0.5	)
Non-current liabilities	(14.6		)	(15.8		)
Net liability at December 31,	$	(15.0	)	$	(16.3	)
Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
Components:
Prior service cost	$	0.3		$	0.4
Net actuarial gain	(5.5		)	(5.0		)
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax	$	(5.2	)	$	(4.6	)
Recorded as:
Regulatory asset	$	0.3		$	0.4
Regulatory liability	(5.1		)	(4.8		)
Accumulated other comprehensive income	(0.4		)	(0.2		)
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax	$	(5.2	)	$	(4.6	)

The accumulated benefit obligation for our defined benefit pension plans was $401.2 million and $431.0 million at December 31, 2015 and 2014, respectively.

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The net periodic benefit cost of the pension and postretirement plans were:

Net Periodic Benefit Cost - Pension
	Years ended December 31,
$ in millions	2015			2014			2013
Service cost	$	7.1		$	5.9		$	7.2
Interest cost	17.3			17.5			15.6
Expected return on assets (a)	(22.6		)	(22.9		)	(23.3		)
Amortization of unrecognized:
Actuarial gain	5.8			3.4			4.9
Prior service cost	2.0			1.5			1.5
Net periodic benefit cost	$	9.6		$	5.4		$	5.9

Net Periodic Benefit Cost - Postretirement
	Years ended December 31,
$ in millions	2015			2014			2013
Service cost	$	0.2		$	0.2		$	0.2
Interest cost	0.6			0.8			0.8
Expected return on assets (a)	(0.1		)	(0.2		)	(0.1		)
Amortization of unrecognized:
Actuarial loss	(0.6		)	(0.6		)	(0.5		)
Prior service cost	0.1			—			—
Net periodic benefit cost	$	0.2		$	0.2		$	0.4

Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities

Pension
	Years ended December 31,
$ in millions	2015			2014			2013
Net actuarial loss / (gain)	$	(3.0	)	$	43.8		$	(12.0	)
Prior service cost	—			6.8			—
Reversal of amortization item:
Net actuarial loss	(5.8		)	(3.4		)	(4.9		)
Prior service cost	(2.0		)	(1.5		)	(1.5		)
Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	(10.8	)	$	45.7		$	(18.4	)
Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	(1.2	)	$	51.1		$	(12.5	)

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Postretirement
	Years ended December 31,
$ in millions	2015			2014		2013
Net actuarial loss / (gain)	$	(1.1	)	$	0.4	$	(2.0	)
Reversal of amortization item:
Net actuarial gain	0.6			0.6		0.5
Prior service cost	$	(0.1	)	$	—	$	—
Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	(0.6	)	$	1.0	$	(1.5	)
Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	(0.4	)	$	1.2	$	(1.1	)

Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2016 are:

$ in millions	Pension		Postretirement
Actuarial gain / (loss)	$	4.3	$	(0.6	)
Prior service cost	$	1.9	$	0.1

Assumptions

Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness.

At December 31, 2015, we are maintaining our long term rate of return assumption of 6.50% for pension plan assets. In addition, we are decreasing our long-term rate of return assumption to 3.90% from 4.50% for other postemployment benefit plan assets. These rates of return represent our long-term assumptions based on our long-term portfolio mixes. Also, at December 31, 2015, we have increased our assumed discount rate to 4.49% from 4.02% for pension and to 4.10% from 3.71% for postemployment benefits expense to reflect current duration-based yield curve discount rates. A one percent increase in the rate of return assumption for pension would result in a decrease in pension expense of approximately $3.5 million. A one percent decrease in the rate of return assumption for pension would result in an increase in pension expense of approximately $3.5 million. A 25 basis point increase in the discount rate for pension would result in a decrease of approximately $0.2 million to 2016 pension expense. A 25 basis point decrease in the discount rate for pension would result in an increase of approximately $0.3 million to 2016 pension expense. A one percent change in the assumed health care cost trend rate would affect postemployment benefit costs by less than $1.0 million.

In determining the discount rate to use for valuing liabilities, we used a market yield curve on high-quality fixed income investments as of December 31, 2015. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are then discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.

Effective January 1, 2016, we will apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. See Note 1 – Overview and Summary of Significant Accounting Policies for more information.

In future periods, differences in the actual return on pension and other post-employment benefit plan assets and assumed return, or changes in the discount rate, will affect the timing of contributions, if any to the plans.

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The weighted average assumptions used to determine benefit obligations at December 31, 2015, 2014 and 2013 were:

Benefit Obligation Assumptions	Pension			Postretirement
	2015	2014	2013	2015	2014	2013
Discount rate for obligations	4.49%	4.02%	4.86%	4.10%	3.71%	4.58%
Rate of compensation increases	3.94%	3.94%	3.94%	N/A	N/A	N/A

The weighted-average assumptions used to determine net periodic benefit cost (income) for the years ended December 31, 2015, 2014 and 2013 were:

Net Periodic Benefit Cost / (Income) Assumptions	Pension			Postretirement
	2015	2014	2013	2015	2014	2013
Discount rate	4.02%	4.86%	4.04%	3.81%	4.51%	4.58%
Expected rate of return on plan assets	6.50%	6.75%	6.75%	4.50%	6.00%	6.00%
Rate of compensation increases	3.94%	3.94%	3.94%	N/A	N/A	N/A

The assumed health care cost trend rates at December 31, 2015, 2014 and 2013 are as follows:

Health Care Cost Assumptions	Expense			Benefit Obligation
	2015	2014	2013	2015	2014	2013
Pre - age 65
Current health care cost trend rate	6.97%	7.75%	8.00%	6.85%	6.97%	7.75%
Year trend reaches ultimate	2029	2023	2019	2036	2029	2023
Post - age 65
Current health care cost trend rate	6.97%	6.75%	7.50%	6.85%	6.97%	6.75%
Year trend reaches ultimate	2029	2021	2018	2036	2029	2021
Ultimate health care cost trend rate	4.50%	5.00%	5.00%	4.50%	4.50%	5.00%

The assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects on the net periodic postemployment benefit cost and the accumulated postemployment benefit obligation:

Effect of change in health care cost trend rate
$ in millions	One-percent increase		One-percent decrease
Service cost plus interest cost	$	0.1	$	—
Benefit obligation	$	0.8	$	(0.7	)

Pension plan assets

Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.

Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of plan equity investments.

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Long-term strategic asset allocation guidelines, as well as short-term tactical asset allocation guidelines, are determined by a Risk/Advisory Committee and approved by a Fiduciary Committee. These allocations take into account the Plan’s long-term objectives. The long-term target allocations for plan assets are 18% – 38% for equity securities and 58% – 86% for fixed income securities. Equity securities include U.S. and international equity, while fixed income securities include long-duration and high-yield bond funds and emerging market debt funds.

Tactically, the committees, on a short-term basis, will make asset allocations that are outside the long-term allocation guidelines. The short-term allocation positions are likely to not exceed one-year in duration. In addition to the equity and fixed income investments, the short-term allocation may also include a relatively small allocation to alternative investments. The plan currently has a small allocation to a core property fund, as well as a small allocation to a hedge fund.

Most of our Plan assets are measured using quoted, observable prices which are considered Level One inputs in the Fair Value Hierarchy. The Core property collective fund and the Common collective fund are measured using Level Two inputs that are quoted prices for identical assets in markets that are less active.

The following table summarizes our target pension plan allocation for 2015:

		Percentage of plan assets as of December 31,
Asset category	Long-Term Mid-Point Target Allocation	2015	2014
Equity Securities	28%	17%	18%
Debt Securities	72%	67%	69%
Real Estate	—%	9%	7%
Other	—%	7%	6%

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The fair values of our pension plan assets at December 31, 2015 by asset category are as follows:

Fair Value Measurements for Pension Plan Assets at December 31, 2015
Asset Category $ in millions	Market Value at December 31, 2015		Quoted prices in active markets for identical assets		Significant observable inputs		Significant unobservable inputs
			(Level 1)		(Level 2)		(Level 3)
Equity securities(a)
Small/Mid cap equity	$	9.2	$	9.2	$	—	$	—
Large cap equity	20.2		20.2		—		—
International equity	18.2		18.2		—		—
Emerging markets equity	2.7		2.7		—		—
SIIT dynamic equity	10.0		10.0		—		—
Total equity securities	60.3		60.3		—		—
Debt securities(b)
Emerging markets debt	6.3		6.3		—		—
High yield bond	6.3		6.3		—		—
Long duration fund	219.5		219.5		—		—
Total debt securities	232.1		232.1		—		—
Other investments(c)
Core property collective fund	30.2		—		30.2		—
Common collective fund	22.8		—		22.8		—
Total other investments	53.0		—		53.0		—
Total pension plan assets	$	345.4	$	292.4	$	53.0	$	—

(a) This category includes investments in equity securities of large, small and medium sized companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(c) This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

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The fair values of our pension plan assets at December 31, 2014 by asset category are as follows:

Fair Value Measurements for Pension Plan Assets at December 31, 2014
Asset Category $ in millions	Market Value at December 31, 2014		Quoted prices in active markets for identical assets		Significant observable inputs		Significant unobservable inputs
			(Level 1)		(Level 2)		(Level 3)
Equity securities(a)
Small/Mid cap equity	$	10.6	$	10.6	$	—	$	—
Large cap equity	22.2		22.2		—		—
International equity	18.2		18.2		—		—
Emerging markets equity	2.8		2.8		—		—
SIIT dynamic equity	11.6		11.6		—		—
Total equity securities	65.4		65.4		—		—
Debt securities(b)
Emerging markets debt	6.0		6.0		—		—
High yield bond	6.5		6.5		—		—
Long duration fund	242.7		242.7		—		—
Total debt securities	255.2		255.2		—		—
Cash and cash equivalents(c)
Cash	1.6		1.6		—		—
Other investments(d)
Core property collective fund	26.3		—		26.3		—
Common collective fund	23.2		—		23.2		—
Total other investments	49.5		—		49.5		—
Total pension plan assets	$	371.7	$	322.2	$	49.5	$	—

(a) This category includes investments in equity securities of large, small and medium sized companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(c) This category comprises cash held to pay beneficiaries. The fair value of cash equals its book value.

(d) This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

The fair values of our other postemployment benefit plan assets at December 31, 2015 by asset category are as follows:

Fair Value Measurements for Other Postemployment Benefit Plan Assets at December 31, 2015
Asset Category $ in millions	Market Value at December 31, 2015		Quoted prices in active markets for identical assets		Significant observable inputs		Significant unobservable inputs
			(Level 1)		(Level 2)		(Level 3)
JP Morgan Core Bond Fund (a)	$	2.8	$	2.8	$	—	$	—

(a) This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities.

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The fair values of our other postemployment benefit plan assets at December 31, 2014 by asset category are as follows:

Fair Value Measurements for Other Postemployment Benefit Plan Assets at December 31, 2014
Asset Category $ in millions	Market Value at December 31, 2014		Quoted prices in active markets for identical assets		Significant observable inputs		Significant unobservable inputs
			(Level 1)		(Level 2)		(Level 3)
JP Morgan Core Bond Fund (a)	$	3.3	$	3.3	$	—	$	—

(a) This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities.

Pension funding

We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. We contributed $5.0 million, $0.0 million, and $0.0 million to the pension plan during the years ended December 31, 2015, 2014 and 2013, respectively.

We expect to make contributions of $0.4 million to our SERP in 2016 to cover benefit payments. We also expect to contribute $1.1 million to our other postemployment benefit plans in 2016 to cover benefit payments. We made contributions of $5.0 million to our pension plan during January 2016.

The Pension Protection Act of 2006 (the Act) contained new requirements for our single employer defined benefit pension plan. In addition to establishing a 100% funding target for plan years beginning after December 31, 2008, the Act also limits some benefits if the funded status of pension plans drops below certain thresholds. Among other restrictions under the Act, if the funded status of a plan falls below a predetermined ratio of 80%, lump-sum payments to new retirees are limited to 50% of amounts that otherwise would have been paid and new benefit improvements may not go into effect. For the 2015 plan year, the funded status of our defined benefit pension plan as calculated under the requirements of the Act was 112.54% and is estimated to be 112.54% until the 2016 status is certified in September 2016 for the 2016 plan year. The Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), which was signed into law on December 23, 2008, grants plan sponsors certain relief from funding requirements and benefit restrictions of the Act.

Benefit payments, which reflect future service, are expected to be paid as follows:

Estimated future benefit payments and Medicare Part D reimbursements
$ in millions due within the following years:	Pension		Postretirement
2016	$	24.6	$	1.7
2017	$	25.2	$	1.6
2018	$	25.8	$	1.5
2019	$	26.3	$	1.4
2020	$	26.7	$	1.4
2021 - 2025	$	134.8	$	5.7

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Note 11 – Equity

Redeemable Preferred Stock of Subsidiary

DP&L has $100 par value preferred stock, 4,000,000 shares authorized, of which 228,508 were outstanding at December 31, 2015 and 2014. DP&L also has $25 par value preferred stock, 4,000,000 shares authorized, none of which was outstanding at December 31, 2015 or 2014. The table below details the preferred shares outstanding at December 31, 2015:

		December 31, 2015 and 2014			Carrying Value (a) ($ in millions)
	Preferred Stock Rate	Redemption price ($ per share)		Shares Outstanding	December 31, 2015		December 31, 2014
DP&L Series A	3.75%	$	102.50	93,280	$	7.4	$	7.4
DP&L Series B	3.75%	$	103.00	69,398	5.6		5.6
DP&L Series C	3.90%	$	101.00	65,830	5.4		5.4
Total				228,508	$	18.4	$	18.4

(a) Carrying value is fair value at the Merger date plus cumulative accrued dividends, of which there were none at December 31, 2015 and 2014.

The DP&L preferred stock may be redeemed at DP&L’s option as determined by its Board of Directors at the per-share redemption prices indicated above, plus cumulative accrued dividends, of which there were none at December 31, 2015. In addition, DP&L’s Amended Articles of Incorporation contain provisions that permit preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Since this potential redemption-triggering event is not solely within the control of DP&L, the preferred stock is presented on the Consolidated Balance Sheets as “Redeemable Preferred Stock” in a manner consistent with temporary equity.

Dividend Restrictions

DPL’s Amended Articles of Incorporation (the Articles) contain provisions which state that DPL may not make a distribution to its shareholder or make a loan to any of its affiliates (other than its subsidiaries), unless: (a) there exists no Event of Default (as defined in the Articles) and no such Event of Default would result from the making of the distribution or loan; and either (b)(i) at the time of, and/or as a result of, the distribution or loan, DPL’s leverage ratio does not exceed 0.67 to 1.00 and DPL’s interest coverage ratio is not less than 2.50 to 1.00 or, (b)(ii) if such ratios are not within the parameters, DPL’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. Further, the restrictions on the payment of distributions to a shareholder and the making of loans to its affiliates (other than subsidiaries) cease to be in effect if the three major credit rating agencies confirm that a lowering of DPL’s senior long-term debt rating below investment grade by the credit rating agencies would not occur without these restrictions.

As long as any DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation also contain provisions restricting the payment of cash dividends on any of its common stock if, after giving effect to such dividend, the aggregate of all such dividends distributed subsequent to December 31, 1946 exceeds the net income of DP&L available for dividends on its common stock subsequent to December 31, 1946, plus $1.2 million. This dividend restriction has historically not affected DP&L’s ability to pay cash dividends and, at December 31, 2015, DP&L’s retained earnings of $437.3 million were all available for common stock dividends payable to DPL. We do not expect this restriction to have an effect on the payment of cash dividends in the future. DPL records dividends on preferred stock of DP&L within Interest expense on the Statements of Operations.

Common Stock

Effective on the Merger date, DPL adopted Amended Articles of Incorporation providing for 1,500 authorized common shares, of which one share is outstanding at December 31, 2015.

As described above,DPL’s Amended Articles of Incorporation contain restrictions on DPL’s ability to make dividends, distributions and affiliate loans (other than to its subsidiaries), including restrictions of making such dividends, distributions and loans if certain financial ratios exceed specified levels and DPL’s senior long-term debt rating from a rating agency is below investment grade. As of December 31, 2015, DPL’s leverage ratio was at 1.03

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to 1.00 and DPL’s senior long-term debt rating from all three major credit rating agencies was below investment grade. As a result, as of December 31, 2015, DPL was prohibited under its Articles of Incorporation from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).

DP&L has 250,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2015. 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 of at least 50 percent and not to have a negative retained earnings balance.

Note 12 – Contractual Obligations, Commercial Commitments and Contingencies

DPL – Guarantees

In the normal course of business, DPL enters into various agreements with its wholly-owned subsidiaries, DPLE and DPLER, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes.

At December 31, 2015, DPL had $17.3 million of guarantees on behalf of DPLE to third parties for future financial or performance assurance under such agreements. In addition, DPL had $1.9 million of guarantees on behalf of DPLER which were released in January 2016 as a result of the sale of DPLER. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of DPLE and present obligations of DPLER to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. All guarantees on behalf of DPLER were terminated in January 2016. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Consolidated Balance Sheets was $0.5 million and $1.6 million at December 31, 2015 and 2014, respectively.

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

Equity Ownership Interest

DP&L has a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. At December 31, 2015, DP&L could be responsible for the repayment of 4.9%, or $74.5 million, of a $1,519.9 million debt obligation comprised of both fixed and variable rate securities with maturities between 2016 and 2040. This would only happen if this electric generation company defaulted on its debt payments. At December 31, 2015, we have no knowledge of such a default.

Contractual Obligations and Commercial Commitments

We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2015, these include:

	Payments due in:
$ in millions	Total	Less than 1 year	2 - 3 years	4 - 5 years	More than 5 years
DPL:
Coal contracts (a)	374.2	186.9	187.3	—	—
Purchase orders and other contractual obligations	83.8	24.4	30.0	29.4	—

(a) Total at DP&L operated units.

Coal contracts:

DPL, through its principal subsidiary DP&L, has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. At December 31, 2015, 73% of our future committed coal obligations are with a single supplier. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.

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Purchase orders and other contractual obligations:

At December 31, 2015, DPL had various other contractual obligations, including non-cancelable contracts, to purchase goods and services with various terms and expiration dates.

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our 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, including the matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2015, 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 SIPs) 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 global climate changes,

• Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO₂, particulates, mercury, acid gases, NO_X, 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 and the Ohio EPA that require reporting and reductions of GHGs,

• Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and

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

In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have accruals for loss contingencies of approximately$0.9 million for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.

We have several pending environmental matters associated with our coal-fired generation units. Some of these matters could have material adverse impacts on the operation of the power stations.

Note 13 – Related Party Transactions

Service Company

In December 2013, an agreement was signed, effective January 1, 2014, whereby 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

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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.

The following table provides a summary of these transactions:

	For the years ended December 31,
$ in millions	2015			2014
Transactions with the Service Company
Charges for services provided	$	36.0		$	35.8
Charges to the Service Company	$	6.2		$	2.4
Transactions with the Service Company:	At December 31, 2015			At December 31, 2014
Net payable to the Service Company	$	(0.5	)	$	(4.7	)

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 December 31, 2015 and 2014, respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $15.6 million and $15.6 million at December 31, 2015 and 2014, respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 8 – Debt for additional information.

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

Income taxes

AES files federal and state income tax returns which consolidate DPL and its subsidiaries. Under a tax sharing agreement with AES, DPL is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. DPL had a net payable balance under this agreement of $50.5 million and $16.1 million as of December 31, 2015 and 2014, respectively, which is recorded in Accrued taxes on the accompanying Consolidated Balance Sheets.

Note 14 – Business Segments

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

The Competitive Retail segment, DPLER’s competitive retail electric service business, was sold on January 1, 2016 (see Note 16 – Discontinued Operations). DPL now operates through one segment, the Utility segment. Segment disclosures for 2014 and 2013 have not been restated to show the competitive retail segment as a discontinued operation and therefore do not tie to the Statements of Operations.

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and deliver electricity to residential, commercial, industrial and governmental customers. DP&L generates electricity at five coal-fired electric generating stations and distributes electricity to approximately 517,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L also sold electricity to DPLER and any excess energy and capacity is sold into the wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators, while its generation business is deemed competitive under Ohio law.

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

Included 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 debt. Management evaluates segment performance based on gross margin. The accounting policies of the reportable segments are the same as those described in Note 1 – Overview and Summary of Significant Accounting Policies. Intersegment sales and profits are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting segments.

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

$ in millions	Utility		Other			Adjustments and Eliminations			DPL Consolidated
Year ended December 31, 2015
Revenues from external customers	$	1,550.8	$	62.0		$	—		$	1,612.8
Intersegment revenues	1.5		4.2			(5.7		)	—
Total revenues	1,552.3		66.2			(5.7		)	1,612.8
Fuel	244.7		15.1			—			259.8
Purchased power	555.7		8.9			(2.0		)	562.6
Gross margin(a)	$	751.9	$	42.2		$	(3.7	)	$	790.4
Depreciation and amortization	$	138.2	$	(3.6	)	$	—		$	134.6
Goodwill impairment (Note 7)	$	—	$	317.0		$	—		$	317.0
Fixed asset impairment	$	—	$	—		$	—		$	—
Interest expense	$	30.9	$	87.6		$	(0.2	)	$	118.3
Income tax expense / (benefit)	$	35.1	$	(15.1	)	$	—		$	20.0
Net income / (loss) from continuing operations	$	106.4	$	(357.8	)	$	—		$	(251.4	)
Discontinued operations, net of tax	$	—	$	12.4		$	—		$	12.4
Net income / (loss)	$	106.4	$	(345.4	)	$	—		$	(239.0	)
Cash capital expenditures	$	127.0	$	10.2		$	—		$	137.2
Total assets (end of year) (b)	$	3,365.8	$	1,314.4		$	(1,339.4	)	$	3,340.8

(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.

(b) Includes assets held for sale related to the sale of DPLER.

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$ in millions	Utility		Competitive Retail		Other			Adjustments and Eliminations			DPL Consolidated
Year ended December 31, 2014
Revenues from external customers	$	1,181.2	$	533.6	$	48.2		$	—		$	1,763.0
Intersegment revenues	487.1		—		5.5			(492.6		)	—
Total revenues	1,668.3		533.6		53.7			(492.6		)	1,763.0
Fuel	314.9		—		(10.4		)	—			304.5
Purchased power	582.4		491.8		7.5			(489.1		)	592.6
Amortization of intangibles	—		—		1.2			—			1.2
Gross margin (a)	$	771.0	$	41.8	$	55.4		$	(3.5	)	$	864.7
Depreciation and amortization	$	144.8	$	0.8	$	(5.8	)	$	—		$	139.8
Goodwill impairment (Note 7)	$	—	$	—	$	135.8		$	—		$	135.8
Fixed asset impairment	$	—	$	—	$	11.5		$	—		$	11.5
Interest expense	$	33.9	$	0.5	$	92.9		$	(0.7	)	$	126.6
Income tax expense / (benefit)	$	39.7	$	2.0	$	(23.5	)	$	—		$	18.2
Net income / (loss)	$	115.0	$	3.2	$	(192.8	)	$	—		$	(74.6	)
Cash capital expenditures	$	114.2	$	2.5	$	1.4		$	—		$	118.1
Total assets (end of year)	$	3,338.7	$	94.9	$	1,440.1		$	(1,295.9	)	$	3,577.8

(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.

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$ in millions	Utility		Competitive Retail		Other			Adjustments and Eliminations			DPL Consolidated
Year ended December 31, 2013
Revenues from external customers	$	1,098.2	$	511.6	$	27.1		$	—		$	1,636.9
Intersegment revenues	453.3		—		4.0			(457.3		)	—
Total revenues	1,551.5		511.6		31.1			(457.3		)	1,636.9
Fuel	362.5		—		4.2			—			366.7
Purchased power	381.9		459.7		1.1			(453.7		)	389.0
Amortization of intangibles	—		—		7.1			—			7.1
Gross margin (a)	$	807.1	$	51.9	$	18.7		$	(3.6	)	$	874.1
Depreciation and amortization	$	140.2	$	0.6	$	(7.9	)	$	—		$	132.9
Goodwill impairment (Note 7)	$	—	$	—	$	306.3		$	—		$	306.3
Fixed asset impairment	$	86.0	$	—	$	(59.8	)	$	—		$	26.2
Interest expense	$	37.2	$	0.5	$	86.9		$	(0.6	)	$	124.0
Income tax expense / (benefit)	$	18.6	$	4.2	$	(0.5	)	$	—		$	22.3
Net income / (loss)	$	83.6	$	6.6	$	(312.2	)	$	—		$	(222.0	)
					$	—
Cash capital expenditures	$	122.1	$	—	$	2.3		$	—		$	124.4
Total assets (end of year)	$	3,313.1	$	105.0	$	1,675.8		$	(1,372.4	)	$	3,721.5

(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.

Note 15 – Fixed-asset Impairment

	Years ended December 31,
	2015		2014		2013
East Bend (DP&L)	$	—	$	11.5	$	—
Conesville (DP&L)	—		—		26.2
Total fixed-asset impairment expense	$	—	$	11.5	$	26.2

East Bend (DP&L) - During the first quarter of 2014, DPL tested the recoverability of long-lived assets at East Bend, a 186 MW coal-fired plant in Kentucky jointly-owned by DP&L. Indications during that quarter that the fair value of the asset group was less than its carrying amount were determined to be impairment indicators given how narrowly these long-lived assets had passed the recoverability test during the fourth quarter of 2013. DPL performed a long-lived asset impairment test and determined that the carrying amount of the asset group was not recoverable. The East Bend asset group was determined to have a fair value of $2.7 million using the market approach. As a result, we recognized an asset impairment expense of $11.5 million. East Bend is reported in the Utility segment, however, this impairment is shown within Other in Note 14 – Business Segments due to acquisition adjustments at DPL which were not pushed down to the utility segment. In May 2014, an agreement was signed for the sale of DP&L’s interest in the generating assets at East Bend. This transaction closed on December 30, 2014.

Conesville (DP&L) - During the fourth quarter of 2013, DPL tested the recoverability of the long-lived assets at Conesville, a 129 MW coal-fired station in Ohio jointly-owned by DP&L. Gradual decreases in power prices as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit failing step 1 of the annual goodwill impairment test were determined to be an impairment indicator for long-lived assets. DPL performed a long-lived asset impairment test and determined that the carrying amount of the asset group was not recoverable. The long-lived asset group subject to the impairment evaluation was determined to be each individual station of

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DP&L. This determination was based on the assessment of the stations’ ability to generate independent cash flows. The Conesville asset group was determined to have zero fair value using discounted cash flows under the income approach. As a result, DPL recognized an asset impairment expense of $26.2 million. Conesville is reported in the Utility segment.

Note 16 – 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 is 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. As the cash received was restricted upon receipt, it is not included within the Statement of Cash Flows. Assets and liabilities related to DPLER have been reclassified to "Assets held for sale" and "Liabilities held for sale" in the December 31, 2015 and 2014 Balance Sheets. We expect to record a gain on this transaction of approximately $56.0 million, net of tax, in the first quarter of 2016. The gain includes the impact of deferred taxes and DPLER’s liability to DP&L that transferred with the sale on January 1, 2016 but was eliminated in consolidation at December 31, 2015 and 2014. 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 Statements of Operations for the years ended December 31, 2015, 2014 and 2013.

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 for the periods indicated:

$ in millions	December 31,
	2015			2014
Accounts receivable, net	$	31.0		$	64.4
Property, plant & equipment, net	4.6			4.9
Intangible assets, net	24.6			29.6
Other assets	2.0			2.9
Total assets of the disposal group classified as held for sale in the balance sheets	$	62.2		$	101.8
Accounts payable	$	0.8		$	14.8
Other liabilities	0.8			2.5
Total liabilities of the disposal group classified as held for sale in the balance sheets	$	1.6		$	17.3
	Years ended December 31,
	2015			2014			2013
Revenues	$	340.9		$	533.6		$	511.6
Cost of revenues	(307.0		)	(493.0		)	(466.8		)
Operating expenses	(22.5		)	(34.0		)	(38.8		)
Goodwill impairment	—			(135.8		)	—
Profit / (loss) of discontinued operations before income taxes	11.4			(129.2		)	6.0
Income tax benefit / (expense)	(1.0		)	2.6			2.4
Income / (loss) on discontinued operations	$	12.4		$	(131.8	)	$	3.6

DPLER purchased its power from DP&L during the periods presented. 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.

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Cash flows related to discontinued operations are included in our Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $35.8 million, $29.6 million and $(7.7) million for the years ended December 31, 2015, 2014 and 2013, respectively. Cash flows from investing activities for discontinued operations were $0.5 million, $(2.2) million and $(2.0) million for the years ended December 31, 2015, 2014, and 2013, respectively. All cash generated from discontinued operations was paid to DPL through dividends for all years presented.

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FINANCIAL STATEMENTS

The Dayton Power and Light Company

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of The Dayton Power and Light Company

We have audited the accompanying balance sheets of The Dayton Power and Light Company (DP&L) as of December 31, 2015 and 2014, and the related statements of operations, comprehensive income, cash flows, and shareholder’s equity for each of the three years in the period ended December 31, 2015. Our audit also included the financial statement schedule “Schedule II - Valuation and Qualifying Accounts” for each of the three years in the period ended December 31, 2015. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of DP&L at December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

February 23, 2016

Indianapolis, Indiana

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THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF OPERATIONS
	Years ended December 31,
$ in millions	2015			2014			2013
Revenues	$	1,552.3		$	1,668.3		$	1,551.5
Cost of revenues:
Fuel	244.7			314.9			362.5
Purchased power	555.7			582.4			381.9
Total cost of revenues	800.4			897.3			744.4
Gross margin	751.9			771.0			807.1
Operating expenses:
Operation and maintenance	350.5			355.2			364.2
Depreciation and amortization	138.2			144.8			140.2
General taxes	85.0			85.7			74.3
Fixed asset impairment	—			—			86.0
Other	0.4			(3.5		)	2.5
Total operating expenses	574.1			582.2			667.2
Operating income	177.8			188.8			139.9
Other income / (expense), net
Investment income	0.3			0.9			2.0
Interest expense	(30.9		)	(33.9		)	(37.2		)
Charge for early redemption of debt	(5.0		)	—			—
Other deductions	(0.7		)	(1.1		)	(2.5		)
Other expense, net	(36.3		)	(34.1		)	(37.7		)
Earnings from operations before income tax	141.5			154.7			102.2
Income tax expense	35.1			39.7			18.6
Net income	106.4			115.0			83.6
Dividends on preferred stock	0.9			0.9			0.9
Earnings attributable to common stock	$	105.5		$	114.1		$	82.7

See Notes to Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF COMPREHENSIVE INCOME
	Years ended December 31,
$ in millions	2015			2014			2013
Net income	$	106.4		$	115.0		$	83.6
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax benefit / (expense) of $0.1, $0.2 and $0.9 for each respective period	(0.2		)	(0.3		)	(1.6		)
Reclassification to earnings, net of income tax benefit / (expense) of $0.0, ($0.2) and ($0.7) for each respective period	—			0.2			1.4
Total change in fair value of available-for-sale securities	(0.2		)	(0.1		)	(0.2		)
Derivative activity:
Change in derivative fair value, net of income tax benefit / (expense) of ($10.3), $10.5 and ($0.6) for each respective period	18.2			(18.8		)	1.0
Reclassification of earnings, net of income tax benefit / (expense) of $5.6, ($11.5) and ($2.5) for each respective period	(9.8		)	15.4			2.6
Total change in fair value of derivatives	8.4			(3.4		)	3.6
Pension and postretirement activity:
Prior service cost for the period, net of income tax benefit / (expense) of $0.0, $1.3 and ($0.2) for each respective period	—			(2.3		)	0.5
Net loss for the period, net of income tax benefit / (expense) of ($1.0), $7.2 and ($1.9) for each respective period	1.7			(12.5		)	4.3
Reclassification to earnings, net of income tax benefit / (expense) of ($1.9), ($1.5) and ($1.9) for each respective period	3.7			2.7			3.8
Total change in unfunded pension and postretirement obligation	5.4			(12.1		)	8.6
Other comprehensive income / (loss)	13.6			(15.6		)	12.0
Net comprehensive income	$	120.0		$	99.4		$	95.6

See Notes to Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY
BALANCE SHEETS
$ in millions	December 31, 2015			December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	5.4		$	5.4
Restricted cash	44.8			16.7
Accounts receivable, net (Note 2)	119.5			152.7
Inventories (Note 2)	108.0			99.0
Taxes applicable to subsequent years	79.2			75.4
Regulatory assets, current (Note 3)	14.4			44.2
Other prepayments and current assets	48.1			41.1
Total current assets	419.4			434.5
Property, plant and equipment:
Property, plant and equipment	5,244.7			5,120.7
Less: Accumulated depreciation and amortization	(2,584.0		)	(2,495.7		)
	2,660.7			2,625.0
Construction work in process	78.0			75.4
Total net property, plant and equipment	2,738.7			2,700.4
Other non-current assets:
Regulatory assets, non-current (Note 3)	179.9			167.5
Intangible assets, net of amortization (Note 1)	5.0			7.8
Other deferred assets	22.8			28.5
Total other non-current assets	207.7			203.8
Total Assets	$	3,365.8		$	3,338.7
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Current portion - long-term debt (Note 7)	$	444.9		$	0.1
Short-term debt	35.0			—
Accounts payable	94.1			104.8
Accrued taxes	86.2			82.6
Accrued interest	4.1			9.8
Customer security deposits	15.1			34.5
Regulatory liabilities, current (Note 3)	24.4			4.4
Other current liabilities	51.0			44.8
Advance on contract termination	27.7			—
Total current liabilities	782.5			281.0
Non-current liabilities:
Long-term debt (Note 7)	318.0			877.0
Deferred taxes (Note 8)	631.2			650.0
Taxes payable	82.1			78.4
Regulatory liabilities, non-current (Note 3)	127.0			124.1
Pension, retiree and other benefits (Note 9)	87.1			95.9
Unamortized investment tax credit	20.0			22.4
Other deferred credits	82.3			43.6
Total non-current liabilities	1,347.7			1,891.4
Redeemable preferred stock of subsidiary (Note 10)	22.9			22.9
Commitments and contingencies (Note 11)
Common shareholder's equity:
Common stock, 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	803.7			803.5
Accumulated other comprehensive loss	(28.7		)	(42.3		)
Retained earnings	437.3			381.8
Total common shareholder's equity	1,212.7			1,143.4
Total Liabilities and Shareholder's Equity	$	3,365.8		$	3,338.7

See Notes to Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF CASH FLOWS
	Years ended December 31,
$ in millions	2015			2014			2013
Cash flows from operating activities:
Net income	$	106.4		$	115.0		$	83.6
Adjustments to reconcile Net income (loss) to Net cash from operating activities
Depreciation and amortization	138.2			144.8			140.2
Amortization of deferred financing costs	2.9			3.1			1.5
Unrealized loss (gain) on derivatives	5.7			2.1			1.3
Deferred income taxes	(19.2		)	7.5			(16.8		)
Fixed-asset impairment	—			—			86.0
Loss / (Gain) on asset disposal	0.4			(3.5		)	2.5
Changes in certain assets and liabilities:
Accounts receivable	28.7			(7.1		)	15.0
Inventories	(9.1		)	(24.6		)	27.2
Prepaid taxes	(1.3		)	(1.1		)	0.4
Taxes applicable to subsequent years	(3.7		)	(6.9		)	(1.8		)
Deferred regulatory costs, net	21.8			5.4			7.8
Accounts payable	(5.8		)	32.4			(5.9		)
Accrued taxes payable	7.3			9.0			(9.1		)
Accrued interest payable	(5.7		)	0.1			(3.4		)
Other current and deferred liabilities	(9.3		)	(18.1		)	5.9
Pension, retiree and other benefits	(0.7		)	19.1			1.8
Unamortized investment tax credit	(2.4		)	(2.5		)	(2.5		)
Other	2.5			(23.0		)	1.6
Net cash from operating activities	256.7			251.7			335.3
Cash flows from investing activities:
Capital expenditures	(127.0		)	(114.2		)	(122.1		)
Decrease / (increase) in restricted cash	(0.3		)	(3.7		)	(2.3		)
Purchase of renewable energy credits	(0.8		)	(3.5		)	(3.9		)
Proceeds from sale of property	—			10.7			0.8
Insurance proceeds	5.2			0.9			14.2
Other investing activities, net	0.4			1.3			(1.2		)
Net cash from investing activities	(122.5		)	(108.5		)	(114.5		)
Cash flows from financing activities
Dividends paid on common stock to parent	(50.0		)	(159.0		)	(190.0		)
Dividends paid on preferred stock	(0.9		)	(0.9		)	(0.9		)
Retirement of long-term debt	(314.4		)	(0.1		)	(470.1		)
Issuance of long-term debt	200.0			—			445.0
Deferred financing costs	(3.9		)	(0.7		)	(10.4		)
Borrowings from revolving credit facilities	50.0			—			—
Repayment of borrowings from revolving credit facilities	(50.0		)	—			—
Borrowings from related party	35.0			15.0			—
Repayment of borrowings from related party	—			(15.0		)	—
Net cash from financing activities	(134.2		)	(160.7		)	(226.4		)
Cash and cash equivalents:
Net increase / (decrease) in cash	—			(17.5		)	(5.6		)
Balance at beginning of period	5.4			22.9			28.5
Cash and cash equivalents at end of period	$	5.4		$	5.4		$	22.9
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	27.5		$	26.6		$	41.5
Income taxes (refunded) / paid, net	$	0.8		$	0.7		$	(20.3	)
Non-cash financing and investing activities:
Accruals for capital expenditures	$	16.9		$	16.3		$	14.7

See Notes to Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF SHAREHOLDER'S EQUITY
	Common Stock (a)
$ in millions (except Outstanding Shares)	Outstanding Shares	Amount		Other Paid-in Capital		Accumulated Other Comprehensive Income / (Loss)			Retained Earnings			Total
Beginning balance	41,172,173	$	0.4	$	803.3	$	(38.7	)	$	534.1		$	1,299.1
Year ended December 31, 2013
Net comprehensive income						12.0			83.6			95.6
Common stock dividends									(190.0		)	(190.0		)
Preferred stock dividends									(0.9		)	(0.9		)
Other				0.2					—			0.2
Ending balance	41,172,173	0.4		803.5		(26.7		)	426.8			1,204.0
Year ended December 31, 2014
Net comprehensive income						(15.6		)	115.0			99.4
Common stock dividends									(159.0		)	(159.0		)
Preferred stock dividends									(0.9		)	(0.9		)
Other									(0.1		)	(0.1		)
Ending balance	41,172,173	0.4		803.5		(42.3		)	381.8			1,143.4
Year ended December 31, 2015
Net comprehensive income						13.6			106.4			120.0
Common stock dividends									(50.0		)	(50.0		)
Preferred stock dividends									(0.9		)	(0.9		)
Other				0.2								0.2
Ending balance	41,172,173	$	0.4	$	803.7	$	(28.7	)	$	437.3		$	1,212.7

(a) $0.01 par value, 250,000,000 shares authorized.

See Notes to Financial Statements.

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The Dayton Power and Light Company

Notes to Financial Statements

For the years ended December 31, 2015, 2014 and 2013

Note 1 – Overview and Summary of Significant Accounting Policies

Description of Business

DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission services are still regulated. DP&L has the exclusive right to provide such service to its approximately517,000customers located in West Central Ohio. Additionally, DP&L procures and provides retail SSO electric service to residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio and generates electricity atfivecoal-fired power stations. Beginning in 2014, DP&L no longer supplied100% of the generation for SSO customers and starting January 2016, SSO is now100%competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the general economic conditions, seasonal weather patterns of the area and the market price of electricity. DP&L sells any excess energy and capacity into the wholesale market. DP&L also sold electricity to DPLER, an affiliate, to satisfy the electric requirements of its retail customers.

In accordance with the ESP Order, on December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets. On July 14, 2014, DP&L announced its decision to retain DP&L’s generation assets. On September 17, 2014 the PUCO ordered that DP&L’s application as amended and updated was approved. DP&L is required to sell or transfer its generation assets by January 1, 2017 and continues to look at multiple options to effectuate the separation, including transfer into an unregulated affiliate of DPL or through a sale.

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

DP&L employed 1,189 people at January 31, 2016. Approximately 61% of all employees are under a collective bargaining agreement which expires on October 31, 2017.

Financial Statement Presentation

DP&L does not have any subsidiaries. DP&L has undivided ownership interests in five electric generating facilities and numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro rata basis in DP&L’s Financial Statements.

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

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; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.

Revenue Recognition

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our statements of operations using an accrual method for retail and other energy sales that have not yet been billed, but where

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electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class.

All of the power produced at the generation stations is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity.

Allowance for Uncollectible Accounts

We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collections efforts have been exhausted.

Property, Plant and Equipment

We record our ownership share of our undivided interest in jointly-held stations as an asset in property, plant and equipment. New property, plant and equipment additions are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $2.0 million, $1.5 million, and $1.5 million for the years ended December 31, 2015, 2014 and 2013, respectively.

For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest.

For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization.

Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable.

Repairs and Maintenance

Costs associated with maintenance activities, primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.

Depreciation

Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DP&L’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. For DP&L’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 2.6% in 2015, 2.8% in 2014 and 4.4% in 2013. Depreciation was $132.7 million, $141.6 million and $136.5 million for the years ended December 31, 2015, 2014 and 2013, respectively.

During the fourth quarter of 2015, DP&L tested the recoverability of long-lived assets at certain generating stations. See Note 13 – Fixed-asset Impairment for more information. Gradual decreases in power prices as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit of DPL failing step 1 of the annual goodwill impairment test were collectively determined to be an impairment indicator.

Regulatory Accounting

As a regulated utility, we apply the provisions of FASC 980 “Regulated Operations”, which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC. Regulatory assets generally represent incurred

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costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DP&L expects to incur in the future.

The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 3 – Regulatory Assets and Liabilities for more information.

Inventories

Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations.

Intangibles

Intangibles include emission allowances and renewable energy credits. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are carried on a weighted average cost basis and amortized as they are used or retired.

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish an allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Our tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting. Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. Our policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Statement of Operations.

Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets with a corresponding deferred tax liability. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 3 – Regulatory Assets and Liabilities for additional information.

DPL and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 8 – Income Taxes for additional information.

Financial Instruments

We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholders’ equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost bases for public equity security and fixed maturity investments are average cost and amortized cost, respectively.

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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. DP&L’s excise taxes and certain other taxes are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements of Operations. The amounts for the years ended December 31, 2015, 2014 and 2013 were $49.9 million, $50.8 million and $50.5 million, respectively.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. At December 31, 2015, restricted cash also includes cash received in connection with the January 1, 2016 contract termination canceling DP&L's power sales contracts with DPLER. See Note 14 – Subsequent Event for additional information regarding this contract termination.

Financial Derivatives

All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.

We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. These purchases are used to hedge our full load requirements. We also hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in fair value being recorded within accumulated other comprehensive income, a component of shareholder’s equity. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 6 – Derivative Instruments and Hedging Activities for additional information.

Insurance and Claims Costs

In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us, other DPL subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, and property damage on an ongoing basis. MVIC maintains an active run-off policy for directors’ and officers’ liability and fiduciary through their expiration in 2017, which may or may not be renewed at that time. DP&L is responsible for claim costs below certain coverage thresholds of MVIC and third party insurers for the insurance coverage noted above. DP&L has estimated liabilities for medical, life, and disability reserves for claims costs below certain coverage thresholds of MVIC and third-party providers. We recorded these additional insurance and claims costs of approximately $13.7 million and $15.6 million at December 31, 2015 and 2014, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined using certain assumptions. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.

Pension and Postretirement Benefits

We recognize, in our Balance Sheets, an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status recognized in AOCI, except for those portions of our pension and postretirement obligations that can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans.

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Effective January 1, 2016, we will apply a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and post-retirement plans. This approach is consistent with the requirements of ASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation.

The change in discount rate approach did not have an impact on the measurement of the benefit obligations at December 31, 2015, nor will it impact future remeasurements. This change in approach will impact the service cost and interest cost recorded in 2016 and future years. It will also impact the actuarial gains and losses recorded in future years, as well as the amortization thereof.

The expected 2016 service costs and interest costs included in Note 9 – Benefit Plans reflect the change in methodology described above. The impact of the change in approach on expected service costs in 2016 is shown below:

$ in millions	Expected 2016 Service Cost							Expected 2016 Interest Cost
	Disaggregated rate approach		Aggregate rate approach		Impact of change			Disaggregated rate approach		Aggregate rate approach		Impact of change
Total Pension	$	5.7	$	6.1	$	(0.4	)	$	14.8	$	17.9	$	(3.1	)
Total Postretirement Benefits	$	0.2	$	0.2	$	—		$	0.6	$	0.7	$	(0.1	)
Total	$	5.9	$	6.3	$	(0.4	)	$	15.4	$	18.6	$	(3.2	)

See Note 9 – Benefit Plans for more information.

Related Party Transactions

In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL or AES.

See Note 12 – Related Party Transactions for additional information on Related Party Transactions.

New accounting pronouncements adopted

ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes

Effective December 31, 2015, we prospectively adopted ASU No. 2015-17, which requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. As a result, each jurisdiction will now only have one net noncurrent deferred tax asset or liability. The guidance does not change the existing requirement that only permits offsetting within a jurisdiction; that is, companies will remain prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. Additionally, the current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the update. As we elected to apply this ASU prospectively, prior periods were not adjusted.

ASU No. 2015-13, Derivatives and Hedging (Topic 815):Derivatives and Hedging: Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Market

In August 2015, the FASB issued ASU No. 2015-13, which resolves the diversity in practice resulting from determining whether certain contracts qualify for the normal purchases and normal sales scope exception under ASC Topic 815, Derivatives and Hedging. This standard clarifies that entities would not be precluded from applying the normal purchases and normal sales exception to certain forward contracts that necessitate the transmission of electricity through, or delivery to a location within, a nodal energy market. The standard is effective upon issuance and should be applied prospectively. As we had designated qualifying contracts as normal purchase or normal sales, there was no impact on our financial statements upon adoption of this standard.

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Accounting pronouncements issued but not yet effective

ASU No. 2016-01, Financial Instruments — Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, which was designed to improve the recognition and measurement of financial instruments through targeted changes to existing GAAP. The guidance requires equity investments (except those that are accounted for under the equity method of accounting or result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income; that entities use the exit price notion when measuring financial instrument fair values; that an entity separate presentation of financial assets and liabilities by measurement category and form of financial asset on the Balance Sheets or Notes to the financial statements; that an entity present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk (or "own credit") when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. Also, the standard eliminates the requirement for public entities to disclose the methods and significant assumptions used to estimate the fair value required to be disclosed for financial instruments measured at amortized cost on the Balance Sheets. The standard is effective beginning with interim periods starting after December 31, 2017 and cannot be applied early. We are currently evaluating the applicability and materiality of the standard, but we do not anticipate a material impact on our financial statements.

ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments

In September 2015, the FASB issued ASU 2015-16, which simplifies the measurement-period adjustments in business combinations. It eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. An acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. The standard is effective for public entities for annual reporting periods beginning after December 15, 2015, and interim periods therein. Early adoption is permitted for financial statements that have not been issued. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date of this standard. We will adopt this standard on January 1, 2016, which is not expected to have a material impact on our

ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30)

In April 2015, the FASB issued ASU No. 2015-03, which simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein, and requires the use of the full retrospective approach. Early adoption is permitted for financial statements that have not been previously issued. As of December 31, 2015DP&L had approximately $6.3 million in deferred financing costs classified in other current and other non-current assets that would be reclassified to reduce the related debt liabilities upon adoption of ASU No. 2015-03.

ASU No. 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements

In August 2015, the FASB issued ASU No. 2015-15, which clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This standard should be adopted concurrent with adoption of ASU 2015-03 (which is described above). As of December 31, 2015, we had deferred financing costs related to lines of credit of approximately $0.7 million recorded within Other noncurrent assets that would not be reclassified upon adoption of this standard.

ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory

In July 2015, the FASB issued ASU No. 2015-11, which simplifies the subsequent measurement of inventory. It replaces the current lower of cost or market test with a lower of cost or net realizable value test. The standard is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted. The new guidance must be applied prospectively. As we already used the net realizable value to make lower of cost or market determinations, there will be no impact on our financial statements upon adoption of this standard.

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ASU No. 2015-05, Intangibles – Goodwill and Other: Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued ASU No. 2015-05, which clarifies how customers in cloud computing arrangements should determine whether the arrangement includes a software license and eliminates the existing requirement for customers to account for software licenses they acquired by analogizing to the accounting guidance on leases. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits the use of a prospective or retrospective approach. As all of our cloud computing arrangements will continue to be accounted for as service agreements, there will be no impact on our financial statements upon the adoption of this standard.

ASU No. 2014-05, Presentation of Financial Statements: Going Concern

The FASB recently issued ASU 2014-15 “Presentation of Financial Statements - Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern)” effective for annual and interim periods ending after December 15, 2016. ASU 2014-15 requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of: principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern. This ASU is not expected to have any impact on our overall results of operations, financial position or cash flows.

ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)

In May 2014, the FASB issued ASU No. 2014-09, which clarifies principles for recognizing revenue and will result in a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The objective of the new standard is to provide 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 of when it is recognized. 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. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contract with Customers (Topic 606): Deferral of the Effective Date, which deferred the effective date of ASU 2014-09 by one year, resulting in the new revenue standard being effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. Early adoption is now permitted only as of the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). The standard permits the use of either a full retrospective or modified retrospective approach. We have not yet selected a transition method and are currently evaluating the impact of adopting the standard on our financial statements.

ASU No. 2015-02, Consolidation – Amendments to the Consolidation Analysis (Topic 810)

In February 2015, the FASB issued ASU 2015-02, which makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the Variable Interest Entity (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. The standard is effective for annual periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. We do not expect this standard to have an impact on our financial statements upon adoption.

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Note 2 – Supplemental Financial Information

	December 31,
$ in millions	2015			2014
Accounts receivable, net
Unbilled revenue	$	43.3		$	49.0
Customer receivables	54.1			68.7
Amounts due from partners in jointly-owned stations	16.0			15.2
Other	6.9			20.7
Provisions for uncollectible accounts	(0.8		)	(0.9		)
Total accounts receivable, net	$	119.5		$	152.7
Inventories
Fuel and limestone	$	72.2		$	65.3
Plant materials and supplies	33.7			32.3
Other	2.1			1.4
Total inventories, at average cost	$	108.0		$	99.0

Accumulated Other Comprehensive Income (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2015, 2014 and 2013 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) Components	Affected line item in the Statements of Operations	Years ended December 31,
$ in millions		2015			2014			2013
Gains and losses on Available-for-sale securities activity (Note 5):
	Other income / (deductions)	$	—		$	0.4		$	2.1
	Tax expense	—			(0.2		)	(0.7		)
	Net of income taxes	—			0.2			1.4
Gains and losses on cash flow hedges (Note 6):
	Interest expense	(1.1		)	(1.1		)	(2.1		)
	Revenue	(18.7		)	28.4			2.2
	Purchased power	4.4			(0.4		)	5.0
	Total before income taxes	(15.4		)	26.9			5.1
	Tax expense	5.6			(11.5		)	(2.5		)
	Net of income taxes	(9.8		)	15.4			2.6
Amortization of defined benefit pension items (Note 9):
	Reclassification to Other income / (deductions)	5.6			4.1			5.7
	Tax benefit	(1.9		)	(1.4		)	(1.9		)
	Net of income taxes	3.7			2.7			3.8
Total reclassifications for the period, net of income taxes		$	(6.1	)	$	18.3		$	7.8

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The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2015 and 2014 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 at December 31, 2013	$	0.8		$	6.2		$	(33.7	)	$	(26.7	)
Other comprehensive loss before reclassifications	(0.3		)	(18.8		)	(14.8		)	(33.9		)
Amounts reclassified from accumulated other comprehensive income	0.2			15.4			2.7			18.3
Net current period other comprehensive loss	(0.1		)	(3.4		)	(12.1		)	(15.6		)
Balance at December 31, 2014	0.7			2.8			(45.8		)	(42.3		)
Other comprehensive income / (loss) before reclassifications	(0.2		)	18.2			1.7			19.7
Amounts reclassified from accumulated other comprehensive income / (loss)	—			(9.8		)	3.7			(6.1		)
Net current period other comprehensive income / (loss)	(0.2		)	8.4			5.4			13.6
Balance at December 31, 2015	$	0.5		$	11.2		$	(40.4	)	$	(28.7	)

Note 3 – Regulatory Assets and Liabilities

In accordance with FASC 980, we have recognized total regulatory assets of $194.3 million and $211.7 million at December 31, 2015 and 2014, respectively, and total regulatory liabilities of $151.4 million and $128.5 million at December 31, 2015 and 2014, respectively. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 1 – Overview and Summary of Significant Accounting Policies for accounting policies regarding Regulatory Assets and Liabilities.

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The following table presents DP&L’s Regulatory assets and liabilities:

			December 31,
$ in millions	Type of Recovery	Amortization Through	2015		2014
Regulatory assets, current:
Fuel and purchased power recovery costs	A	2016	$	13.9	$	16.3
Economic development costs	A	2016	0.5		2.1
Deferred storm costs	B	2015	—		22.3
Energy efficiency program	A	2016	—		1.8
Other miscellaneous	A	2016	—		1.7
Total regulatory assets, current			$	14.4	$	44.2
Regulatory assets, non-current:
Pension benefits	B	Ongoing	$	91.6	$	99.6
Deferred recoverable income taxes	B/C	Ongoing	36.4		43.1
Fuel costs	B	Undetermined	12.7		—
Unrecovered OVEC charges	D	Undetermined	10.5		—
Unamortized loss on reacquired debt	B	Various	9.0		9.9
Smart grid and advanced metering infrastructure costs	D	Undetermined	7.3		6.6
Generation separation costs		Undetermined	3.9		1.6
Retail settlement system costs	D	Undetermined	3.1		3.1
Consumer education campaign	D	Undetermined	3.0		3.0
Rate case costs	D	Undetermined	1.9		—
Other miscellaneous	D	Undetermined	0.5		0.6
Total regulatory assets, non-current			$	179.9	$	167.5
Total regulatory assets			$	194.3	$	211.7
Regulatory liabilities, current:
Energy efficiency program			$	9.2	$	—
Competitive bidding			9.1		—
Transmission costs			3.7		2.9
Reconciliation rider			2.1		—
Other miscellaneous			0.3		1.5
Total regulatory liabilities, current			$	24.4	$	4.4
Regulatory liabilities, non-current:
Estimated costs of removal - regulated property			$	121.8	$	119.3
Postretirement benefits			5.2		4.8
Total regulatory liabilities, non-current			$	127.0	$	124.1
Total regulatory liabilities			$	151.4	$	128.5

A – Recovery of incurred costs without a rate of return.

B – Recovery of incurred costs plus rate of return.

C – Balance has an offsetting liability resulting in no effect on rate base.

D – Recovery not yet determined, but is probable of occurring in future rate proceedings.

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Regulatory assets

Fuel and purchased power recovery costsrepresent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider. The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. As part of the PUCO approval process, an outside auditor reviews fuel costs and the fuel procurement process. The audit for 2014 is in process. The costs recovered through the fuel rider have decreased significantly over the past three years as more SSO supply is provided through the competitive bid. While no further fuel or purchased power costs will be recoverable through the rider, it will continue for up to six months to allow for recovery of the ending deferral amount.

Fuel costs - long-term represent unrecovered fuel costs related to DP&L’s fuel rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.

Economic development costs represent costs incurred to promote economic development within the State of Ohio. These costs are being recovered through an Economic Development Rider that is subject to a bi-annual true-up process for any over/under recovery of costs.

Deferred storm costs represent costs incurred to repair the damage to DP&L’s distribution equipment by major storms in 2008, 2011 and 2012. All such costs have now been recovered.

Energy efficiency program costsrepresent costs incurred to develop and implement various customer programs addressing energy efficiency. These costs are being recovered through an Energy Efficiency Rider (EER) that began July 1, 2009 and that is subject to an annual true-up for any over/under recovery of costs. In addition to recovery of program costs, this rider has allowed for DP&L to recover lost margin associated with decreases in sales as a result of the programs implemented. The authority to recover lost margin included a maximum amount, which DP&L reached in the fourth quarter of 2015. Consequently, we discontinued accruing an asset for lost revenues after the maximum was reached. In addition, this rider provides that DP&L can earn a “shared savings” incentive that is tiered depending upon the level of success the programs reach. In 2014 and 2015, the maximum shared savings was accrued based upon performance, which is equal to $4.5 million per year, after income taxes.

Pension benefitsrepresent the qualifying FASC 715 “Compensation - Retirement Benefits” costs of our regulated operations that for ratemaking purposes are deferred for future recovery. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory asset represents the regulated portion that would otherwise be charged as a loss to OCI.

Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow-through items as the result of tax benefits previously provided to customers. This is the cumulative flow-through benefit given to regulated customers that will be collected from them in future years. Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, these deferred recoverable income taxes will decrease over time.

Unrecovered OVEC charges represent the portion of capacity charges from OVEC that were not recoverable through DP&L’s fuel rider beginning in October 2014. DP&L expects to recover these costs through a future rate proceeding.

Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with FERC and PUCO rules.

Smart Grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and the implementation of AMI. On October 19, 2010, DP&L elected to withdraw its case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities' Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate,

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file new Smart Grid and/or AMI business cases in the future. This plan is currently under development and we plan to seek recover of these deferred costs in a regulatory rate proceeding in the near future. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates.

Generation separation costs represent financing, redemption and other costs related to the divestiture of DP&L’s generation assets. The PUCO directed DP&L to divest its generation assets by January 1, 2017. DP&L requested and was granted permission by the PUCO to defer all financing, redemption and related costs it incurs to transfer its generation assets. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.

Retail settlement system costsrepresent costs to implement a retail settlement system that reconciles the energy a CRES supplier delivers to its customers with what its customers actually use. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.

Consumer education campaignrepresents costs for consumer education advertising regarding electric deregulation. DP&L has requested recovery of these costs as part of its pending distribution rate case filing.

Rate case costs represent costs associated with preparing a distribution rate case. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.

Regulatory liabilities

Energy efficiency program costs see “Regulatory Assets - Energy efficiency program costs” above.

Competitive bidding represents costs associated with the development and implementation of a Competitive Bidding Process, establishing contracts to supply power for a portion of DP&L’s Standard Service Offer load, as well as the net over/under recovery of the cost of the power purchased from the bid winners.

Transmission costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM. On an annual basis, retail rates are adjusted to true-up costs with recovery in rates.

Reconciliation rider represents the costs that exceed 10 percent of the base amount of the following riders: Fuel, RPM, Alternative Energy and Competitive Bidding. This rider is in an overcollection position and will be discontinued after this overcollection has been refunded to customers.

Estimated costs of removal – regulated property reflect an estimate of amounts collected in customer rates for costs that are expected to be incurred in the future to remove existing transmission and distribution property from service when the property is retired.

Postretirement benefits represent the qualifying FASC 715 “Compensation – Retirement Benefits” gains related to our regulated operations that, for ratemaking purposes, are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be reflected as a gain to OCI.

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Note 4 – Property, Plant and Equipment

The following is a summary of DP&L’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2015 and 2014:

	December 31,
$ in millions	2015		Composite Rate	2014		Composite Rate
Regulated:
Transmission	$	413.7	2.3%	$	402.4	2.3%
Distribution	1,639.7		3.3%	1,568.0		3.5%
General	96.9		8.4%	116.1		6.7%
Non-depreciable	62.5		N/A	61.6		N/A
Total regulated	2,212.8			2,148.1
Unregulated:
Production / Generation	3,016.8		2.1%	2,957.7		2.4%
Non-depreciable	15.1		N/A	14.9		N/A
Total unregulated	3,031.9			2,972.6
Total property, plant and equipment in service	$	5,244.7	2.6%	$	5,120.7	2.8%

DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. At December 31, 2015, DP&L had $39.0 million of construction work in process at such facilities. DP&L’s share of the operations of such facilities is included within the corresponding line in the 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 Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.

Coal-fired facilities

DP&L’s undivided ownership interest in such facilities at December 31, 2015, is as follows:

	DP&L Share		DP&L Carrying Value
	Ownership %	Summer Production Capacity (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)
Jointly-owned production units
Conesville - Unit 4	16.5	129	$	27	$	8	$	1
Killen - Unit 2	67.0	402	655		326		2
Miami Fort - Units 7 and 8	36.0	368	366		171		6
Stuart - Units 1 through 4	35.0	808	772		338		18
Zimmer - Unit 1	28.1	371	1,104		690		12
Transmission (at varying percentages)			99		64		—
Total		2,078	$	3,023	$	1,597	$	39

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

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Beckjord Unit 6 was retired effective October 1, 2014 and DP&L sold its interest in East Bend on December 30, 2014.

As part of the provisional DPL purchase accounting adjustments related to the Merger, four stations (Beckjord, Conesville, East Bend and Hutchings) had future expected cash flows that, when discounted, produced a fair market value different than DP&L’s carrying value. Since DP&L did not apply push down accounting, this valuation did not affect the carrying value of these stations’ valuation at DP&L. In the fourth quarter of 2013, DP&L performed an impairment review of its stations and recorded impairment expense of $86.0 million related to two of its stations, Conesville and East Bend. See Note 13 – Fixed-asset Impairment for more information on these impairments.

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. Our generation AROs are recorded within Other deferred credits on the consolidated balance sheets.

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 December 31, 2013	$	19.9
Calendar 2014
Additions	3.6
Accretion expense	1.1
Settlements	(1.7		)
Balance at December 31, 2014	22.9
Calendar 2015
Additions	40.3
Accretion expense	2.1
Settlements	(3.2		)
Balance at December 31, 2015	$	62.1

Asset Removal Costs

We continue to record cost of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $121.8 million and $119.3 million in estimated costs of removal at December 31, 2015 and 2014, respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 3 – Regulatory Assets and Liabilities for additional information.

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Changes in the Liability for Transmission and Distribution Asset Removal Costs

$ in millions
Balance at December 31, 2013	$	115.0
Calendar 2014
Additions	19.6
Settlements	(15.3		)
Balance at December 31, 2014	119.3
Calendar 2015
Additions	24.3
Settlements	(21.8		)
Balance at December 31, 2015	$	121.8

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 method is available to us. The fair value of our financial instruments represents estimates of possible value that may or may not be realized in the future.

The table below presents the fair value and cost of our non-derivative instruments at December 31, 2015 and 2014. See also Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments.

	December 31, 2015				December 31, 2014
$ in millions	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets
Money market funds	$	0.2	$	0.2	$	0.1	$	0.1
Equity securities	3.0		3.8		2.7		3.7
Debt securities	4.4		4.3		4.7		4.7
Hedge Funds	0.4		0.4		0.8		0.8
Real Estate	0.3		0.3		0.4		0.4
Total assets	$	8.3	$	9.0	$	8.7	$	9.7
Liabilities
Debt	$	762.9	$	764.2	$	877.1	$	882.5

Fair value hierarchy

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

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

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

• Level 3 (unobservable inputs).

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

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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 twelve months ended December 31, 2015 and 2014.

Debt

The fair value of debt is based on current public market prices for disclosure purposes only. Unrealized gains or losses are not recognized in the financial statements as debt is presented at the carrying value, net of unamortized premium or discount, in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2016 to 2061.

Master trust assets

DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.

DP&L had $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 and $1.1 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2014.

Various investments were sold during the past twelve months to facilitate the distribution of benefits. During the past twelve months, an immaterial amount of unrealized gains were reversed into earnings. Over the next twelve months, an immaterial amount of unrealized gains is expected to be reversed to earnings.

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

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2015 (a)		Based on Quoted Prices in Active Markets		Other observable inputs		Unobservable inputs
Assets
Master trust assets
Money market funds	$	0.2	$	0.2	$	—	$	—
Equity securities	3.8		—		3.8		—
Debt securities	4.3		—		4.3		—
Hedge Funds	0.4		—		0.4		—
Real Estate	0.3		—		0.3		—
Total Master trust assets	9.0		0.2		8.8		—
Derivative assets
FTRs	0.2		—		—		0.2
Forward power contracts	30.6		—		30.6		—
Total derivative assets	30.8		—		30.6		0.2
Total assets	$	39.8	$	0.2	$	39.4	$	0.2
Liabilities
FTRs	$	0.5	$	—	$	—	$	0.5
Forward power contracts	27.0		—		23.9		3.1
Total derivative liabilities	27.5		—		23.9		3.6
Long-term debt	764.2		—		746.1		18.1
Total liabilities	$	791.7	$	—	$	770.0	$	21.7

(a) Includes credit valuation adjustment.

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The fair value of assets and liabilities at December 31, 2014 and the respective category within the fair value hierarchy for DP&L was determined as follows:

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2014 (a)		Based on Quoted Prices in Active Markets		Other observable inputs		Unobservable inputs
Assets
Master trust assets
Money market funds	$	0.1	$	0.1	$	—	$	—
Equity securities	3.7		3.7		—		—
Debt securities	4.7		4.7		—		—
Hedge Funds	0.8		—		0.8		—
Real Estate	0.4		0.4		—		—
Total Master trust assets	9.7		8.9		0.8		—
Derivative assets
Forward power contracts	15.1		—		13.9		1.2
Total derivative assets	15.1		—		13.9		1.2
Total assets	$	24.8	$	8.9	$	14.7	$	1.2
Liabilities
Forward power contracts	$	11.2	$	—	$	11.2	$	—
FTRS	0.6		—		—		0.6
Heating Oil Futures	0.4		0.4		—		—
Natural Gas Futures	0.1		0.1		—		—
Total derivative liabilities	12.3		0.5		11.2		0.6
Long-term debt	882.5		—		864.3		18.2
Total liabilities	$	894.8	$	0.5	$	875.5	$	18.8

(a) Includes credit valuation adjustment.

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

• Level 1 inputs are used for derivative contracts, such as heating oil 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 the end of day NAV per unit.

• Level 3 inputs, such as financial transmission rights, are considered a Level 3 input because the monthly auctions are considered inactive. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.

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Our debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. The WPAFB 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 were not presented since debt is not recorded at fair value.

Approximately 99% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Non-recurring Fair Value Measurements

We use the cost approach to determine the fair value of our AROs, which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. AROs for asbestos, ash ponds, underground storage tanks, and river structures increased by a net amount of $39.2 million ($25.5 million after tax) and $3.0 million ($2.0 million after tax) during the 12 months endedDecember 31, 2015 and 2014, respectively. The majority of the increase for 2015 is due to a net increase in the ARO for ash ponds of $40.3 million ($26.2 million after tax) as a result of new rules promulgated by the USEPA that were published in the Federal Register in April 2015 and became effective in October 2015. See Note 4 – Property, Plant and Equipment for more information about AROs.

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 major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:

$ in millions	Year ended December 31, 2013
	Carrying		Fair Value						Gross
	Amount		Level 1		Level 2		Level 3		Loss
Assets
Long-lived assets held and used (a)
Conesville	$	30.0	$	—	$	—	$	20.0	$	10.0
East Bend	$	76.0	$	—	$	—	$	—	$	76.0

(a) See Note 13 – Fixed-asset Impairment for further information.

The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets during the year ended December 31, 2013:

$ in millions	Fair Value		Valuation Technique	Unobservable input	Range (Weighted Average)
Long-lived assets held and used:
DP&L (Conesville)	$	—	Discounted cash flows	Annual revenue growth	-31% to 18% (0)

Note 6 – Derivative Instruments and Hedging Activities

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

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At December 31, 2015, DP&L had the following outstanding derivative instruments:

Commodity	Accounting Treatment	Unit	Purchases (in thousands)	Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	10.2	—		10.2
Forward Power Contracts	Designated	MWh	1,676.7	(7,795.8	)	(6,119.1	)
Forward Power Contracts	Not designated	MWh	5,049.9	(1,665.7	)	3,384.2

At December 31, 2014, DP&L had the following outstanding derivative instruments:

Commodity	Accounting Treatment	Unit	Purchases (in thousands)	Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	10.5	—		10.5
Heating Oil Futures	Not designated	Gallons	378.0	—		378.0
Natural Gas	Not designated	Dths	200.0			200.0
Forward Power Contracts	Designated	MWh	175.0	(2,991.0	)	(2,816.0	)
Forward Power Contracts	Not designated	MWh	1,725.2	(2,804.0	)	(1,078.8	)

Cash flow hedges

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

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

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The following tables set forth the gains / (losses) recognized in AOCI and earnings related to the effective portion of derivative instruments and the gains / (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the periods indicated:

	Years ended December 31,
	2015			2015			2014			2014			2013			2013
$ in millions (net of tax)	Power			Interest Rate Hedge			Power			Interest Rate Hedge			Power			Interest Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	0.2		$	2.6		$	1.0		$	5.2		$	(4.7	)	$	7.3
Net gains / (losses) associated with current period hedging transactions	18.2			—			(18.8		)	—			1.0			—
Net gains / (losses) reclassified to earnings:
Interest Expense	—			(0.6		)	—			(2.6		)	—			(2.1		)
Revenues	(12.0		)	—			18.2			—			1.4			—
Purchased Power	2.8			—			(0.2		)	—			3.3			—
Ending accumulated derivative gain in AOCI	$	9.2		$	2.0		$	0.2		$	2.6		$	1.0		$	5.2
Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented.
Portion expected to be reclassified to earnings in the next twelve months (a)	$	5.9		$	(0.6	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	36			—

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

Derivatives not designated as hedges

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchases and sales exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the consolidated statements of results 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. We mark to market FTRs, heating oil futures and certain forward power contracts.

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

Regulatory assets and liabilities

In accordance with regulatory accounting under GAAP, a cost that is probable of recovery in future rates should be deferred as a regulatory asset and a gain that is probable of being returned to customers should be deferred as a

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regulatory liability. Portions of the derivative contracts that are marked to market each reporting period and are related to the retail portion of DP&L’s load requirements are included as part of the fuel and purchased power recovery rider approved by the PUCO which began January 1, 2010. Therefore, the Ohio retail customers’ portion of the heating oil futures are 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.

The following tables show the amount and classification within the statements of results of operations or balance sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the years ended December 31, 2015, 2014 and 2013.

	Year ended December 31, 2015
$ in millions	Heating Oil			FTRs			Power			Natural Gas			Total
Derivatives not designated as hedging instruments
Change in unrealized loss	$	0.4		$	0.3		$	(6.3	)	$	0.1		$	(5.5	)
Realized gain / (loss)	(0.3		)	(0.2		)	(9.9		)	(0.1		)	(10.5		)
Total	$	0.1		$	0.1		$	(16.2	)	$	—		$	(16.0	)
Recorded on Balance Sheet:
Regulatory asset	$	0.1		$	—		$	—		$	—		$	0.1
Recorded in Income Statement: gain / (loss)
Revenue	—			—			27.4			—			27.4
Purchased Power	—			0.1			(43.6		)	—			(43.5		)
Fuel	—			—			—			—			—
Total	$	0.1		$	0.1		$	(16.2	)	$	—		$	(16.0	)

	Year ended December 31, 2014
$ in millions	Heating Oil			FTRs			Power			Natural Gas			Total
Derivatives not designated as hedging instruments
Change in unrealized gain / (loss)	$	(0.6	)	$	(0.8	)	$	(1.5	)	$	(0.1	)	$	(3.0	)
Realized gain / (loss)	(0.1		)	0.7			(3.0		)	(0.1		)	(2.5		)
Total	$	(0.7	)	$	(0.1	)	$	(4.5	)	$	(0.2	)	$	(5.5	)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1	)	$	—		$	—		$	—		$	(0.1	)
Recorded in Income Statement: gain / (loss)
Revenue	$	—		$	—		$	0.7		$	—		$	0.7
Purchased Power	—			(0.1		)	(5.2		)	(0.2		)	(5.5		)
Fuel	(0.6		)	—			—			—			(0.6		)
Total	$	(0.7	)	$	(0.1	)	$	(4.5	)	$	(0.2	)	$	(5.5	)

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	Year ended December 31, 2013
$ in millions	NYMEX Coal		Heating Oil		FTRs		Power			Total
Derivatives not designated as hedging instruments
Change in unrealized gain / (loss)	$	—	$	—	$	0.3	$	(1.2	)	$	(0.9	)
Realized gain / (loss)	—		0.1		1.2		1.6			2.9
Total	$	—	$	0.1	$	1.5	$	0.4		$	2.0
Recorded on Balance Sheet:
Partners' share of gain	$	—	$	—	$	—	$	—		$	—
Regulatory (asset) / liability	—		—		—		—			—
Recorded in Income Statement: gain / (loss)
Revenue	—		—		—		0.2			0.2
Purchased Power	—		—		1.5		0.2			1.7
Fuel	—		0.1		—		—			0.1
O&M	—		—		—		—			—
Total	$	—	$	0.1	$	1.5	$	0.4		$	2.0

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The following tables show the fair value, balance sheet classification and hedging designation of DP&L’s derivative instruments at December 31, 2015 and 2014.

Fair Values of Derivative Instruments
December 31, 2015
				Gross Amounts Not Offset in the Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Designated	$	16.2	$	(7.1	)	$	—		$	9.1
Forward power contracts	Not designated	7.4		(5.5		)	—			1.9
FTRs		0.2		(0.2		)	—			—
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	3.0		(2.4		)	—			0.6
Forward power contracts	Not designated	4.0		(2.7		)	—			1.3
Total assets		$	30.8	$	(17.9	)	$	—		$	12.9
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	7.1	$	(7.1	)	$	—		$	—
Forward power contracts	Not designated	14.5		(5.5		)	(8.0		)	1.0
FTRs	Not designated	0.5		(0.2		)	—			0.3
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Designated	2.7		(2.4		)	—			0.3
Forward power contracts	Not designated	2.7		(2.7		)	—			—
Total liabilities		$	27.5	$	(17.9	)	$	(8.0	)	$	1.6

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Fair Values of Derivative Instruments
December 31, 2014
				Gross Amounts Not Offset in the Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Designated	$	5.6	$	(2.0	)	$	—		$	3.6
Forward power contracts	Not designated	5.6		(3.4		)	—			2.2
FTRs	Not designated	—		—			—			—
Heating oil futures	Not designated	—		—			—			—
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Designated	0.3		(0.3		)	—			—
Forward power contracts	Not designated	3.6		(0.9		)	—			2.7
Total assets		$	15.1	$	(6.6	)	$	—		$	8.5
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	2.1	$	(2.0	)	$	—		0.1
Forward power contracts	Not designated	7.5		(3.4		)	(4.1		)	—
FTRs	Not designated	0.6		—			—			0.6
Heating oil futures	Not designated	0.4		—			(0.4		)	—
Natural gas futures	Not designated	0.1		—			(0.1		)	—
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Designated	0.6		(0.3		)	(0.3		)	—
Forward power contracts	Not designated	1.0		(0.9		)	—			0.1
Total liabilities		$	12.3	$	(6.6	)	$	(4.9	)	$	0.8

Credit risk-related contingent features

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies. Since our debt has fallen below investment grade, we are in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization of the MTM loss. Some of our counterparties to the derivative instruments have requested collateralization of the MTM loss.

The aggregate fair value of DP&L’s derivative instruments that are in a MTM loss position at December 31, 2015 is $27.5 million. This amount is offset by $8.0 million of collateral 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

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the asset position of counterparties with master netting agreements of $17.9 million. If DP&L debt were to fall below investment grade, DP&L could be required to post collateral for the remaining $1.6 million.

Note 7 – Debt

Long-term debt is as follows:

Long-term debt
$ in millions	Interest Rate	Maturity	December 31, 2015			December 31, 2014
First mortgage bonds	1.875%	2016	$	445.0		$	445.0
Pollution control series	4.7%	2028	—			35.3
Pollution control series	4.8%	2034	—			179.1
Pollution control series	4.8%	2036	100.0			100.0
Pollution control series - rates from: 0.02% - 0.12% and 0.04% - 0.15% (a)		2040	—			100.0
Pollution control series - rates from: 1.13% - 1.17%		2020	200.0			—
U.S. Government note	4.2%	2061	18.1			18.2
Unamortized debt discount			(0.2		)	(0.5		)
Subtotal			762.9			877.1
Less: current portion			(444.9		)	(0.1		)
Total			$	318.0		$	877.0

At December 31, 2015, maturities of long-term debt are summarized as follows:

Due within the twelve months ending December 31,
$ in millions
2016	$	445.1
2017	0.1
2018	0.1
2019	0.2
2020	200.2
Thereafter	117.4
	763.1
Unamortized discount	(0.2		)
Total long-term debt	$	762.9

Significant transactions

On December 31, 2015,DP&L borrowed $35.0 million from DPL at an interest rate of 2.67%. The notes were due on or before December 31, 2016 and were repaid on January 29, 2016.

On July 1, 2015, the $35.3 million of DP&L's4.7% pollution control bonds due January 2028 and $41.3 million of DP&L's4.8% pollution control bonds due January of 2034 were called at par and were redeemed with cash.

On July 31, 2015, DP&L refinanced its revolving credit facility. The new facility has a $175.0 million borrowing limit, a $50.0 million letter of credit sublimit, a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million and a maturity date of July 2020. At December 31, 2015, there were two letters of credit in the amount of $1.4 million outstanding, with the remaining $173.6 million available to DP&L. Fees associated with this revolving credit facility were not material during the years ended December 31, 2015 or 2014. Prior to refinancing the facility on July 31, 2015, this facility had a $300.0 million borrowing limit, a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provided DP&L the ability to increase the size of the facility by an additional $100.0 million.

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On August 3, 2015, DP&L called $100.0 million of variable rate pollution control bonds due November 2040, terminated the amended standby letter of credit facilities that supported these pollution control bonds, and called $137.8 million of 4.8% pollution control bonds due January of 2034. DP&L also used cash to redeem $37.8 million of these bonds and refinanced the $200.0 million balance, with new variable interest rate pollution control bonds secured by first mortgage bonds in an equivalent amount. In connection with the sale of the new pollution control bonds, DP&L entered into a certain Bond Purchase and Covenants Agreement, dated as of August 1, 2015, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L.

On March 31, 2014, DP&L borrowed $15.0 million from DPL at an interest rate of LIBOR plus 2.0%. This note was due on or before April 30, 2014 and was repaid on April 30, 2014.

On September 19, 2013, DP&L closed a $445.0 million issuance of senior secured first mortgage bonds. These new bonds mature on September 15, 2016, and are secured by DP&L’s First & Refunding Mortgage. Substantially all property, plant and equipment of DP&L is subject to the lien of the First and Refunding Mortgage. Substantially concurrent with this transaction, DP&L redeemed $470.0 million of previously outstanding first mortgage bonds.

Debt covenants and restrictions

In connection with DP&L’s sale of $200.0 million of variable rate pollution control bonds dated August 1, 2015, DP&L entered into an unsecured revolving credit agreement and a Bond Purchase and Covenants Agreement. These agreements contain representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L and have two financial covenants. The first measures Total Debt to Total Capitalization and is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.

As of December 31, 2015,DP&Lwas in compliance with all debt covenants, including the financial covenants described above and did not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL.

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Note 8 – Income Taxes

DP&L’s components of income tax expense were as follows:

	Years ended December 31,
$ in millions	2015			2014			2013
Computation of tax expense
Federal income tax expense (a)	$	49.3		$	53.8		$	35.5
Increases (decreases) in tax resulting from:
State income taxes, net of federal effect	0.4			1.2			0.3
Depreciation of AFUDC - Equity	(2.8		)	(2.7		)	(2.5		)
Investment tax credit amortized	(2.4		)	(2.5		)	(2.5		)
Section 199 - domestic production deduction	(6.1		)	(4.6		)	(4.1		)
Accrual (settlement) for open tax years	—			(6.6		)	(8.8		)
Other, net (b)	(3.3		)	1.1			0.7
Total tax expense	$	35.1		$	39.7		$	18.6
Components of Tax Expense
Federal - current	$	55.8		$	34.1		$	38.6
State and Local - current	0.8			0.5			(0.1		)
Total current	56.6			34.6			38.5
Federal - deferred	(21.0		)	4.1			(20.4		)
State and local - deferred	(0.5		)	1.0			0.5
Total deferred	(21.5		)	5.1			(19.9		)
Total tax expense	$	35.1		$	39.7		$	18.6

Effective and Statutory Rate Reconciliation

The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to DP&L's effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 2015, 2014 and 2013:

	Years ended December 31,
	2015		2014		2013
Statutory Federal tax rate	35.0	%	35.0	%	35.0	%
State taxes, net of Federal tax benefit	0.3	%	0.8	%	0.3	%
AFUDC - Equity	(2.0	)%	(1.7	)%	(2.4	)%
Amortization of investment tax credits	(1.7	)%	(1.6	)%	(2.4	)%
Section 199 - domestic production deduction	(4.3	)%	(3.0	)%	(4.0	)%
Other - net	(2.5	)%	(3.8	)%	(8.3	)%
Effective tax rate	24.8	%	25.7	%	18.2	%

Deferred Income Taxes

Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.

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Components of Deferred Tax Assets and Liabilities
	December 31,
$ in millions	2015			2014
Net non-current Assets / (Liabilities)
Depreciation / property basis	$	(608.8	)	$	(618.8	)
Income taxes recoverable	(12.0		)	(14.8		)
Regulatory assets	(11.5		)	(18.0		)
Investment tax credit	7.0			8.6
Compensation and employee benefits	3.6			5.2
Other	(9.5		)	(12.2		)
Net non-current liabilities	$	(631.2	)	$	(650.0	)
Net current Assets / (Liabilities)(c)
Other	$	—		$	0.5
Net current assets / (liabilities)	$	—		$	0.5

(a) The statutory tax rate of 35% was applied to pre-tax earnings.

(b) Includes benefit of $0.4 million, expense of $0.7 million and benefit of $1.1 million in the years ended December 31, 2015, 2014 and 2013, respectively, of income tax related to adjustments from prior years.

(c) Amounts are included within Other prepayments and current assets and Other current liabilities on the Balance Sheets of DP&L.

The following table presents the tax (benefit) / expense related to pensions, postemployment benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss.

	Years ended December 31,
$ in millions	2015		2014			2013
Tax expense / (benefit)	$	7.5	$	(6.0	)	$	7.0

Uncertain Tax Positions

We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits for DP&L is as follows:

$ in millions
Balance at December 31, 2013	$	8.8
Calendar 2014
Tax positions taken during prior period	2.8
Lapse of Statute of Limitations	(8.6		)
Settlement with taxing authorities	—
Balance at December 31, 2014	3.0
Calendar 2015
Tax positions taken during prior period	—
Lapse of Statute of Limitations	—
Balance at December 31, 2015	$	3.0

Of the December 31, 2015 balance of unrecognized tax benefits, $0.9 million is due to uncertainty in the timing of deductibility.

We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The amounts accrued and expense (benefit) recorded were not material for each period presented.

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Following is a summary of the tax years open to examination by major tax jurisdiction:

U.S. Federal – 2010 and forward

State and Local – 2010 and forward

None of the unrecognized tax benefits are expected to significantly increase or decrease within the next twelve months other than those subject to expiring statute of limitations.

The Internal Revenue Service began an examination of our 2008 Federal income tax return during the second quarter of 2010. The results of the examination were approved by the Joint Committee on Taxation on January 18, 2013. As a result of the examination, DPL received a refund of $19.9 million and recorded a $1.2 million reduction to income tax expense in 2013.

Note 9 – Benefit Plans

Defined contribution plans

DP&L sponsors two defined contribution plans. One is for non-union employees (the management plan) and one is for collective bargaining employees (the union plan). Both plans are qualified under Section 401 of the Internal Revenue Code.

Certain non-union employees become eligible to participate in the management plan on the first day of the month following the first full calendar month of employment; provided the employee worked at least 160 hours in that calendar month. Union employees become eligible to participate in the union plan on the first day of the first month following 30 days of employment. Effective January 1, 2016, employees in both plans are eligible to participate upon date of hire.

Participants may elect to contribute up to 85% of eligible compensation to their plan. Non-union participant contributions are matched 100% on the first 1% of eligible compensation and 50% on the next 5% of eligible compensation and they are fully vested in their employer contributions after 2 years of service. Union participant contributions are matched 150% but are capped at $2,100 for 2015 and they are fully vested in their employer contributions after 3 years of service. All participants are fully vested in their own contributions.

For the years ended December 31, 2015, 2014 and 2013DP&L's contributions to all defined contribution plans were $4.8 million, $4.7 million and $4.8 million per year, respectively.

Defined benefit plans

DP&L sponsors a traditional defined benefit pension plan for most of the employees of DPL and its subsidiaries. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the traditional defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this traditional pension plan was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Effective January 1, 2014, the Service Company began providing services including 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. Employees that transferred from DP&L to the Service Company maintain their previous eligibility to participate in the DP&L pension plan.

Almost all management employees beginning employment on or after January 1, 2011 participate in a cash balance pension plan. Similar to the traditional pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment.

In addition, we have a Supplemental Executive Retirement Plan (SERP) for certain retired key executives. The SERP has an immaterial unfunded liability related to agreements for retirement benefits of certain terminated and

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retired key executives. We also include our net liability to our partners related to our share of their pension costs within Pension, retiree and other benefits on our Balance Sheets.

We recognize an asset for a plan’s overfunded status and a liability for a plan’s underfunded status and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. For the transmission and distribution areas of our electric business, these amounts are recorded as regulatory assets and liabilities which represent the regulated portion that would otherwise be charged or credited to AOCI. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered through customer rates. This factor, combined with the historical precedents from the PUCO and FERC, make these costs probable of future rate recovery.

Postretirement benefits

Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from their retirement until they are covered by Medicare. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust.

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The following tables set forth the changes in our pension and postemployment benefit plans’ obligations and assets recorded on the balance sheets at December 31, 2015 and 2014. The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate. The amounts presented for postemployment obligations include both health and life insurance benefits.

$ in millions	Pension
	Years ended December 31,
	2015			2014
Change in benefit obligation
Benefit obligation at beginning of period	$	443.8		$	370.5
Service cost	7.1			5.9
Interest cost	17.3			17.5
Plan amendments	—			6.8
Actuarial (gain) / loss	(34.5		)	67.3
Benefits paid	(22.9		)	(24.2		)
Benefit obligation at end of period	410.8			443.8
Change in plan assets
Fair value of plan assets at beginning of period	371.7			349.1
Actual return on plan assets	(8.8		)	46.4
Contributions to plan assets	5.4			0.4
Benefits paid	(22.9		)	(24.2		)
Fair value of plan assets at end of period	345.4			371.7
Funded status of plan	$	(65.4	)	$	(72.1	)
	December 31,
	2015			2014
Amounts recognized in the Balance sheets
Current liabilities	$	(0.4	)	$	(0.4	)
Non-current liabilities	(65.0		)	(71.7		)
Net liability at Year ended December 31,	$	(65.4	)	$	(72.1	)
Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
Components:
Prior service cost	$	17.0		$	20.3
Net actuarial loss / (gain)	139.7			152.5
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax	$	156.7		$	172.8
Recorded as:
Regulatory asset	$	91.1		$	99.0
Regulatory liability	—			—
Accumulated other comprehensive income	65.6			73.8
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax	$	156.7		$	172.8

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$ in millions	Postretirement
	Years ended December 31,
	2015			2014
Change in benefit obligation
Benefit obligation at beginning of period	$	19.6		$	19.7
Service cost	0.2			0.2
Interest cost	0.6			0.8
Actuarial (gain) / loss	(1.1		)	0.2
Benefits paid	(1.5		)	(1.3		)
Benefit obligation at end of period	17.8			19.6
Change in plan assets
Fair value of plan assets at beginning of period	3.3			3.7
Contributions to plan assets	1.0			0.9
Benefits paid	(1.5		)	(1.3		)
Fair value of plan assets at end of period	2.8			3.3
Funded status of plan	$	(15.0	)	$	(16.3	)
	December 31,
	2015			2014
Amounts recognized in the Balance sheets
Current liabilities	$	(0.4	)	$	(0.5	)
Non-current liabilities	(14.6		)	(15.8		)
Net liability at Year ended December 31,	$	(15.0	)	$	(16.3	)
Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
Components:
Prior service cost	$	0.5		$	0.6
Net actuarial loss / (gain)	(6.2		)	(5.8		)
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax	$	(5.7	)	$	(5.2	)
Recorded as:
Regulatory asset	$	0.3		$	—
Regulatory liability	(5.1		)	(4.5		)
Accumulated other comprehensive income	(0.9		)	(0.7		)
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax	$	(5.7	)	$	(5.2	)

The accumulated benefit obligation for our defined benefit pension plans was $401.2 million and $431.0 million at December 31, 2015 and 2014, respectively.

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The net periodic benefit cost of the pension and postretirement plans were:

Net Periodic Benefit Cost - Pension
	Years ended December 31,
$ in millions	2015			2014			2013
Service cost	$	7.1		$	5.9		$	7.2
Interest cost	17.3			17.5			15.6
Expected return on assets (a)	(22.6		)	(22.9		)	(23.6		)
Amortization of unrecognized:
Actuarial gain	9.8			6.4			9.3
Prior service cost	3.3			2.8			2.8
Net periodic benefit cost	$	14.9		$	9.7		$	11.3

Net Periodic Benefit Cost - Postretirement
	Years ended December 31,
$ in millions	2015			2014			2013
Service cost	$	0.2		$	0.2		$	0.2
Interest cost	0.6			0.8			0.8
Expected return on assets (a)	(0.1		)	(0.2		)	(0.2		)
Amortization of unrecognized:
Actuarial loss	(0.6		)	(0.8		)	(0.7		)
Prior service cost	0.1			0.1			0.1
Net periodic benefit cost	$	0.2		$	0.1		$	0.2

Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities

Pension
	Years ended December 31,
$ in millions	2015			2014			2013
Net actuarial loss / (gain)	$	(3.0	)	$	43.8		$	(11.7	)
Prior service cost	—			6.8			—
Reversal of amortization item:
Net actuarial loss	(9.8		)	(6.4		)	(9.3		)
Prior service cost	(3.3		)	(2.8		)	(2.8		)
Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	(16.1	)	$	41.4		$	(23.8	)
Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	(1.2	)	$	51.1		$	(12.5	)

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Postretirement
	Years ended December 31,
$ in millions	2015			2014			2013
Net actuarial loss / (gain)	$	(1.1	)	$	0.4		$	(1.9	)
Reversal of amortization item:
Net actuarial gain	0.6			0.8			0.7
Prior service credit	(0.1		)	(0.1		)	(0.1		)
Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	(0.6	)	$	1.1		$	(1.3	)
Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	(0.4	)	$	1.2		$	(1.1	)

Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2016 are:

$ in millions	Pension		Postretirement
Actuarial gain / (loss)	$	7.2	$	(0.8	)
Prior service cost	$	3.1	$	0.1

Assumptions

Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness.

At December 31, 2015, we are maintaining our long term rate of return assumption of 6.50% for pension plan assets. In addition, we are decreasing our long-term rate of return assumption to 3.90% from 4.50% for other postemployment benefit plan assets. These rates of return represent our long-term assumptions based on our long-term portfolio mixes. Also, at December 31, 2015, we have increased our assumed discount rate to 4.49% from 4.02% for pension and to 4.10% from 3.71% for postemployment benefits expense to reflect current duration-based yield curve discount rates. A one percent increase in the rate of return assumption for pension would result in a decrease in pension expense of approximately $3.5 million. A 1% decrease in the rate of return assumption for pension would result in an increase in pension expense of approximately $3.5 million. A 25 basis point increase in the discount rate for pension would result in a decrease of approximately $0.2 million to 2016 pension expense. A 25 basis point decrease in the discount rate for pension would result in an increase of approximately $0.3 million to 2016 pension expense. A one percent change in the assumed health care cost trend rate would affect postemployment benefit costs by less than $1.0 million.

In determining the discount rate to use for valuing liabilities, we used a market yield curve on high-quality fixed income investments as of December 31, 2015. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are then discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.

Effective January 1, 2016 we will apply the spot rate approach for determining service cost and interest cost for its defined benefit pension plans and other post-retirement plan. The expected 2016 service costs and interest costs included above reflect the change in methodology. The impact of the change in approach is a reduction in: (1) expected service costs of $0.4 million for pension plans in 2016 ($0.4 million Defined Benefit Pension Plan and $0.0 million Supplemental Retirement Plan), and (2) expected interest costs of $3.2 million for pension plans in 2016 ($3.1 million Defined Benefit Pension Plan and $0.1 million Supplemental Retirement Plan).

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The weighted average assumptions used to determine benefit obligations during the years ended December 31, 2015, 2014 and 2013 were:

Benefit Obligation Assumptions	Pension			Postretirement
	2015	2014	2013	2015	2014	2013
Discount rate for obligations	4.49%	4.02%	4.86%	4.10%	3.71%	4.58%
Rate of compensation increases	3.94%	3.94%	3.94%	N/A	N/A	N/A

The weighted-average assumptions used to determine net periodic benefit cost (income) for the years ended December 31, 2015, 2014 and 2013 were:

Net Periodic Benefit Cost / (Income) Assumptions	Pension			Postretirement
	2015	2014	2013	2015	2014	2013
Discount rate	4.02%	4.86%	4.04%	3.81%	4.51%	4.58%
Expected rate of return on plan assets	6.50%	6.75%	6.75%	4.50%	6.00%	6.00%
Rate of compensation increases	3.94%	3.94%	3.94%	N/A	N/A	N/A

The assumed health care cost trend rates at December 31, 2015, 2014 and 2013 are as follows:

Health Care Cost Assumptions	Expense			Benefit Obligation
	2015	2014	2013	2015	2014	2013
Pre - age 65
Current health care cost trend rate	6.97%	7.75%	8.00%	6.85%	6.97%	7.75%
Year trend reaches ultimate	2029	2023	2019	2036	2029	2023
Post - age 65
Current health care cost trend rate	6.97%	6.75%	7.50%	6.85%	6.97%	6.75%
Year trend reaches ultimate	2029	2021	2018	2036	2029	2021
Ultimate health care cost trend rate	4.50%	5.00%	5.00%	4.50%	4.50%	5.00%

The assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects on the net periodic postemployment benefit cost and the accumulated postemployment benefit obligation:

Effect of change in health care cost trend rate
$ in millions	One-percent increase		One-percent decrease
Service cost plus interest cost	$	0.1	$	—
Benefit obligation	$	1.1	$	(0.7	)

Pension plan assets

Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.

Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of plan equity investments.

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Long-term strategic asset allocation guidelines, as well as short-term tactical asset allocation guidelines, are determined by a Risk/Advisory Committee and approved by a Fiduciary Committee. These allocations take into account the Plan’s long-term objectives. The long-term target allocations for plan assets are 18% – 38% for equity securities and 58% – 86% for fixed income securities. Equity securities include U.S. and international equity, while fixed income securities include long-duration and high-yield bond funds and emerging market debt funds.

Tactically, the committees, on a short-term basis, will make asset allocations that are outside the long-term allocation guidelines. The short-term allocation positions are likely to not exceed one-year in duration. In addition to the equity and fixed income investments, the short-term allocation may also include a relatively small allocation to alternative investments. The plan currently has a small allocation to a core property fund, as well as a small allocation to a hedge fund.

Most of our Plan assets are measured using quoted, observable prices which are considered Level One inputs in the Fair Value Hierarchy. The Core property collective fund and the Common collective fund are measured using Level Two inputs that are quoted prices for identical assets in markets that are less active.

The following table summarizes our target pension plan allocation for 2015:

		Percentage of plan assets as of December 31,
Asset Category	Long-Term Mid-Point Target Allocation	2015	2014
Equity Securities	28%	17%	18%
Debt Securities	72%	67%	69%
Real Estate	—%	9%	7%
Other	—%	7%	6%

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The fair values of our pension plan assets at December 31, 2015 by asset category are as follows:

Fair Value Measurements for Pension Plan Assets at December 31, 2015
Asset Category $ in millions	Market Value at December 31, 2015		Quoted prices in active markets for identical assets		Significant observable inputs		Significant unobservable inputs
			(Level 1)		(Level 2)		(Level 3)
Equity securities(a)
Small/Mid cap equity	$	9.2	$	9.2	$	—	$	—
Large cap equity	20.2		20.2		—		—
International equity	18.2		18.2		—		—
Emerging markets equity	2.7		2.7		—		—
SIIT dynamic equity	10.0		10.0		—		—
Total equity securities	60.3		60.3		—		—
Debt Securities(b)
Emerging markets debt	6.3		6.3		—		—
High yield bond	6.3		6.3		—		—
Long duration fund	219.5		219.5		—		—
Total debt securities	232.1		232.1		—		—
Other investments(c)
Core property collective fund	30.2		—		30.2		—
Common collective fund	22.8		—		22.8		—
Total other investments	53.0		—		53.0		—
Total pension plan assets	$	345.4	$	292.4	$	53.0	$	—

(a) This category includes investments in equity securities of large, small and medium sized companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(c) This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

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The fair values of our pension plan assets at December 31, 2014 by asset category are as follows:

Fair Value Measurements for Pension Plan Assets at December 31, 2014
Asset Category $ in millions	Market Value at December 31, 2014		Quoted prices in active markets for identical assets		Significant observable inputs		Significant unobservable inputs
			(Level 1)		(Level 2)		(Level 3)
Equity securities(a)
Small/Mid cap equity	$	10.6	$	10.6	$	—	$	—
Large cap equity	22.2		22.2		—		—
International equity	18.2		18.2		—		—
Emerging markets equity	2.8		2.8		—		—
SIIT dynamic equity	11.6		11.6		—		—
Total equity securities	65.4		65.4		—		—
Debt Securities(b)
Emerging markets debt	6.0		6.0		—		—
High yield bond	6.5		6.5		—		—
Long duration fund	242.7		242.7		—		—
Total debt securities	255.2		255.2		—		—
Cash and cash equivalents(c)
Cash	1.6		1.6		—		—
Other investments(d)
Core property collective fund	26.3		—		26.3		—
Common collective fund	23.2		—		23.2		—
Total other investments	49.5		—		49.5		—
Total pension plan assets	$	371.7	$	322.2	$	49.5	$	—

(a) This category includes investments in equity securities of large, small and medium sized companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(c) This category comprises cash held to pay beneficiaries. The fair value of cash equals its book value.

(d) This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

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The fair values of our other postemployment benefit plan assets at December 31, 2015 by asset category are as follows:

Fair Value Measurements for Other Postemployment Benefit Plan Assets at December 31, 2015
Asset Category $ in millions	Fair Value at December 31, 2015 (a)		Quoted prices in active markets for identical assets		Significant observable inputs		Significant unobservable inputs
			(Level 1)		(Level 2)		(Level 3)
JP Morgan Core Bond Fund (a)	$	2.8	$	2.8	$	—	$	—

(a) This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities.

The fair values of our other postemployment benefit plan assets at December 31, 2014 by asset category are as follows:

Fair Value Measurements for Other Postemployment Benefit Plan Assets at December 31, 2014
Asset Category $ in millions	Fair Value at December 31, 2014 (a)		Quoted prices in active markets for identical assets		Significant observable inputs		Significant unobservable inputs
			(Level 1)		(Level 2)		(Level 3)
JP Morgan Core Bond Fund (a)	$	3.2	$	3.2	$	—	$	—

(a) This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities.

Pension funding

We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. We contributed $5.0 million, $0.0 million, and $0.0 million during the years ended December 31, 2015, 2014 and 2013, respectively.

We expect to make contributions of $0.4 million to our SERP in 2016 to cover benefit payments. We also expect to contribute $1.1 million to our other postemployment benefit plans in 2016 to cover benefit payments. We made contributions of $5.0 million to our pension plan during January, 2016.

The Pension Protection Act of 2006 (the Act) contained new requirements for our single employer defined benefit pension plan. In addition to establishing a 100% funding target for plan years beginning after December 31, 2008, the Act also limits some benefits if the funded status of pension plans drops below certain thresholds. Among other restrictions under the Act, if the funded status of a plan falls below a predetermined ratio of 80%, lump-sum payments to new retirees are limited to 50% of amounts that otherwise would have been paid and new benefit improvements may not go into effect. For the 2015 plan year, the funded status of our defined benefit pension plan as calculated under the requirements of the Act was 112.54% and is estimated to be 112.54% until the 2016 status is certified in September 2016 for the 2016 plan year. The Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), which was signed into law on December 23, 2008, grants plan sponsors certain relief from funding requirements and benefit restrictions of the Act.

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Benefit payments, which reflect future service, are expected to be paid as follows:

Estimated future benefit payments and Medicare Part D reimbursements
$ in millions due within the following years:	Pension		Postretirement
2016	$	24.6	$	1.7
2017	$	25.2	$	1.6
2018	$	25.8	$	1.5
2019	$	26.3	$	1.4
2020	$	26.7	$	1.4
2021 - 2025	$	134.8	$	5.7

Note 10 – Equity

Redeemable Preferred Stock

DP&L has $100 par value preferred stock, 4,000,000 shares authorized, of which 228,508 were outstanding at December 31, 2015. DP&L also has $25 par value preferred stock, 4,000,000 shares authorized, none of which was outstanding at December 31, 2015. The table below details the preferred shares outstanding at December 31, 2015 and 2014:

		December 31, 2015 and 2014			Par Value ($ in millions)
	Preferred Stock Rate	Redemption price ($ per share)		Shares Outstanding	December 31, 2015		December 31, 2014
DP&L Series A	3.75%	$	102.50	93,280	$	9.3	$	9.3
DP&L Series B	3.75%	$	103.00	69,398	7.0		7.0
DP&L Series C	3.90%	$	101.00	65,830	6.6		6.6
Total				228,508	$	22.9	$	22.9

The DP&L preferred stock may be redeemed at DP&L’s option as determined by its Board of Directors at the per-share redemption prices indicated above, plus cumulative accrued dividends, of which there were none at December 31, 2015. In addition, DP&L’s Amended Articles of Incorporation contain provisions that permit preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Since this potential redemption-triggering event is not solely within the control of DP&L, the preferred stock is presented on the Balance Sheets as “Redeemable Preferred Stock” in a manner consistent with temporary equity.

Dividend Restrictions

As long as any DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation also contain provisions restricting the payment of cash dividends on any of its common stock if, after giving effect to such dividend, the aggregate of all such dividends distributed subsequent to December 31, 1946 exceeds the net income of DP&L available for dividends on its common stock subsequent to December 31, 1946, plus $1.2 million. This dividend restriction has historically not impacted DP&L’s ability to pay cash dividends and, as of December 31, 2015, DP&L’s retained earnings of 437.3 million were all available for common stock dividends payable to DPL. We do not expect this restriction to have an effect on the payment of cash dividends in the future.

Common Stock

DP&L has 250,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2015. 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 of at least 50 percent and not to have a negative retained earnings balance.

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Note 11 – Contractual Obligations, Commercial Commitments and Contingencies

DP&L – Equity Ownership Interest

DP&L has a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. At December 31, 2015, DP&L could be responsible for the repayment of 4.9%, or $74.5 million, of a $1,519.9 million debt obligation comprised of both fixed and variable rate securities with maturities between 2016 and 2040. This would only happen if this electric generation company defaulted on its debt payments. At December 31, 2015, we have no knowledge of such a default.

Contractual Obligations and Commercial Commitments

We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2015, these include:

	Payments due in:
$ in millions	Total	Less than 1 year	2 - 3 years	4 - 5 years	More than 5 years
DP&L:
Coal contracts (a)	374.2	186.9	187.3	—	—
Purchase orders and other contractual obligations	83.8	24.4	30.0	29.4	—

(a) Total at DP&L operated units.

Coal contracts:

DP&L has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. At December 31, 2015, 73% of our future committed coal obligations are with a single supplier. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.

Purchase orders and other contractual obligations:

At December 31, 2015, DP&L had various other contractual obligations, including non-cancelable contracts, to purchase goods and services with various terms and expiration dates.

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our 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, including the matters discussed 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 as of December 31, 2015, 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 SIPs) 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 global climate changes,

• Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO₂, particulates, mercury, acid gases, NO_X, 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 and the Ohio EPA that require reporting and reductions of GHGs,

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• Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and

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

In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have accruals for loss contingencies of approximately$0.9 million for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.

We have several pending environmental matters associated with our coal-fired generation units. Some of these matters could have material adverse impacts on the operation of the power stations.

Note 12 – Related Party Transactions

In December 2013, an agreement was signed, effective January 1, 2014, whereby 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.

The following table provides a summary of these transactions:

	Years ended December 31,
$ in millions	2015			2014			2013
DP&L revenues:
Sales to DPLER (including MC Squared) (a)	$	303.3		$	487.1		$	453.9
DP&L Operation & Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(3.2	)	$	(2.9	)	$	(2.9	)
Expense recoveries for services provided to DPLER (c)	$	2.4		$	2.2		$	5.2
Transactions with the Service Company:
Charges for services provided	$	30.9		$	30.5		$	—
Charges to the Service Company	$	6.1		$	2.3		$	—
Balances with related parties:	At December 31, 2015			At December 31, 2014
Net payable to the Service Company	$	(0.5	)	$	(4.7	)
Short-term loan with DPL Inc.	$	35.0		$	—
Deposits received from DPLER (d)	$	—		$	20.1

(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 on the sale of DPLER on January 1, 2016.

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(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.

(c) In the normal course of business DP&L incurs and records expenses on behalf of DPLER. Such expenses include but are not limited to employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. DP&L subsequently charges these expenses to DPLER at DP&L’s cost and credits the expense in which they were initially recorded.

(d) DP&L requires credit assurance from the CRES providers serving customers in its service territory because DP&L is the default energy provider should the CRES provider fail to fulfill its obligations to provide electricity. Due to DPL’s credit downgrade, DP&L required cash collateral from DPLER.

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 receivable balance under this agreement of $1.5 million and $1.0 million as of December 31, 2015 and 2014, respectively, which is recorded in Other current assets on the accompanying Balance Sheets.

Note 13 – Fixed-asset Impairment

	Years ended December 31,
	2015		2014		2013
East Bend	$	—	$	—	$	76.0
Conesville	—		—		10.0
Total fixed-asset impairment expense	$	—	$	—	$	86.0

East Bend and Conesville - During the fourth quarter of 2013, DP&L tested the recoverability of long-lived assets at Conesville, a 129 MW coal-fired station in Ohio, and East Bend, a 186 MW coal-fired station in Kentucky jointly-owned by DP&L. Gradual decreases in power prices, as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit of DPL failing step 1 of the annual goodwill impairment test were collectively determined to be an impairment indicator for the DP&L long-lived assets. DP&L performed a long-lived asset impairment test and determined that the carrying amounts of the asset groups were not recoverable. The long-lived asset group subject to the impairment evaluation was determined to be each individual station of DP&L. This determination was based on the assessment of the stations’ ability to generate independent cash flows. The Conesville and East Bend asset groups were each determined to have a zero fair value using discounted cash flows under the income approach. As a result, DP&L recognized an asset impairment expense of $10.0 million and $76.0 million for Conesville and East Bend, respectively.

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Note 14 – Subsequent Event

On January 1, 2016, DPL closed on the sale of DPLER to IGS. 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, which we expect to record as a gain in the first quarter of 2016. This amount is shown as Restricted cash with the associated liability shown as Advance on contract termination on the Balance Sheet as of December 31, 2015. As the cash we received was restricted upon receipt it is not shown on the Statement of Cash Flows.

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PART IV

Item 15 – Exhibits, Financial Statements and Financial Statement Schedules

The following documents are filed as part of this report:
1.      Financial Statements
DPL – Report of Independent Registered Public Accounting Firms	11
DPL – Consolidated Statements of Operations for each of the three years in the period ended December 31, 2015	13
DPL – Consolidated Statements of Other Comprehensive Loss for each of the three years in the period ended December 31, 2015	14
DPL – Consolidated Balance Sheets at December 31, 2015 and 2014	15
DPL – Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2015	16
DPL – Consolidated Statement of Shareholder’s Equity for each of the three years in the period ended December 31, 2015	17
DPL – Notes to Consolidated Financial Statements	18
DP&L – Report of Independent Registered Public Accounting Firm	70
DP&L – Statements of Operations for each of the three years in the period ended December 31, 2015	72
DP&L – Consolidated Statements of Other Comprehensive Income for each of the three years in the period ended December 31, 2015	73
DP&L – Balance Sheets at December 31, 2015 and 2014	74
DP&L – Statements of Cash Flows for each of the three years in the period ended December 31, 2015	75
DP&L – Statement of Shareholder’s Equity for each of the three years in the period ended December 31, 2015	76
DP&L – Notes to Financial Statements	77

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Exhibits

DPL and DP&L exhibits are incorporated by reference as described unless otherwise filed as set forth herein.

The exhibits filed as part of DPL’s and DP&L’s Annual Report on Form 10-K, respectively, are:

DPL	DP&L	Exhibit Number	Exhibit	Location
X		2(a)	Agreement and Plan of Merger, dated as of April 19, 2011, by and among DPL Inc., The AES Corporation and Dolphin Sub, Inc.	Exhibit 2.1 to Report on Form 8-K filed April 20, 2011 (File No. 1-9052)
X		3(a)	Amended Articles of Incorporation of DPL Inc., as amended through January 6, 2012	Exhibit 3(a) to Report on Form 10-K for the year ended December 31, 2011 (File No. 1-2385)
X		3(b)	Amended Regulations of DPL Inc., as amended through November 28, 2011	Exhibit 3.2 to Report on Form 8-K filed November 28, 2011 (File No. 1-9052)
	X	3(c)	Amended Articles of Incorporation of The Dayton Power and Light Company, as of January 4, 1991	Exhibit 3(b) to Report on Form 10-K/A for the year ended December 31, 1991 (File No. 1-2385)
	X	3(d)	Regulations of The Dayton Power and Light Company, as of April 9, 1981	Exhibit 3(a) to Report on Form 8-K filed on May 3, 2004 (File No. 1-2385)
X	X	4(a)	Composite Indenture dated as of October 1, 1935, between The Dayton Power and Light Company and Irving Trust Company, Trustee with all amendments through the Twenty-Ninth Supplemental Indenture	Exhibit 4(a) to Report on Form 10-K for the year ended December 31, 1985 (File No. 1-2385)
X	X	4(b)	Forty-First Supplemental Indenture dated as of February 1, 1999, between The Dayton Power and Light Company and The Bank of New York, Trustee	Exhibit 4(m) to Report on Form 10-K for the year ended December 31, 1998 (File No. 1-2385)
X	X	4(c)	Forty-Second Supplemental Indenture dated as of September 1, 2003, between The Dayton Power and Light Company and The Bank of New York, Trustee	Exhibit 4(r) to Report on Form 10-K for the year ended December 31, 2003 (File No. 1-9052)
X	X	4(d)	Forty-Third Supplemental Indenture dated as of August 1, 2005, between The Dayton Power and Light Company and The Bank of New York, Trustee	Exhibit 4.4 to Report on Form 8-K filed August 24, 2005 (File No. 1-2385)
X		4(e)	Indenture dated as of August 31, 2001 between DPL Inc. and The Bank of New York, Trustee	Exhibit 4(a) to Registration Statement No. 333-74630
X		4(f)	First Supplemental Indenture dated as of August 31, 2001 between DPL Inc. and The Bank of New York, as Trustee	Exhibit 4(b) to Registration Statement No. 333-74630
X		4(g)	Amended and Restated Trust Agreement dated as of August 31, 2001 among DPL Inc., The Bank of New York, The Bank of New York (Delaware), the administrative trustees named therein, and several Holders as defined therein	Exhibit 4(c) to Registration Statement No. 333-74630
X	X	4(h)	Forty-Fourth Supplemental Indenture dated as of September 1, 2006 between the Bank of New York, Trustee and The Dayton Power and Light Company	Exhibit 4(s) to Report on Form 10-K for the year ended December 31, 2009 (File No. 1-2385)

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DPL	DP&L	Exhibit Number	Exhibit	Location
X		4(i)	Indenture, dated October 3, 2011, between Dolphin Subsidiary II, Inc. and Wells Fargo Bank, National Association	Exhibit 4.1 to Report on Form 8-K filed October 5, 2011 by The AES Corporation (File No. 1-12291)
X		4(j)	Supplemental Indenture, dated as of November 28, 2011, between DPL Inc. and Wells Fargo Bank, National Association	Exhibit 4(k) to Report on Form 10-K for the year ended December 31, 2011 (File No. 1-2385)
X		4(k)	Registration Rights Agreement, dated October 3, 2011, between Dolphin Subsidiary II, Inc. and Merrill Lynch Pierce Fenner & Smith Incorporated and each of the initial purchasers named therein	Exhibit 4(l) to Report on Form 10-K for the year ended December 31, 2011 (File No. 1-2385)
	X	4(l)	Registration Rights Agreement, dated as of September 19, 2013, by and between Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC, as representatives of the initial purchasers	Exhibit 4.1 to Report on Form 8-K filed September 25, 2013 (File No. 1-2385)
	X	4(m)	47th Supplemental Indenture to the First and Refunding Mortgage, dated as of September 1, 2013, by and between the Bank of New York Mellon, as Trustee, and The Dayton Power and Light Company	Exhibit 4.2 to Report on Form 8-K filed September 25, 2013 (File No. 1-2385)
X		4(n)	Indenture, dated October 6, 2014, between DPL Inc. and U.S. Bank National Association.	Exhibit 4.1 to Report on Form 8-K filed October 10, 2014 (File No. 1-9052)
X		4(o)	Registration Rights Agreement, dated as of October 6, 2014, by and between DPL Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC, as representatives of the initial purchasers.	Exhibit 4.1 to Report on Form 8-K filed October 10, 2014 (File No. 1-9052)
X	X	4(p)	Loan Agreement, dated August 1, 2015, between the Ohio Air Quality Development Authority and The Dayton Power and Light Company, relating to the 2015 Series A pollution control bonds	Exhibit 4.1 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
X	X	4(q)	Loan Agreement, dated August 1, 2015, between the Ohio Air Quality Development Authority and The Dayton Power and Light Company, relating to the 2015 Series B pollution control bonds	Exhibit 4.2 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
X	X	4(r)	Forty-Eighth Supplemental Indenture dated as of August 1, 2015 between The Bank of New York Mellon, Trustee and The Dayton Power and Light Company	Exhibit 4.3 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
X	X	4(s)	Forty-Ninth Supplemental Indenture dated as of August 1, 2015 between The Bank of New York Mellon, Trustee and The Dayton Power and Light Company	Exhibit 4.4 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)

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DPL	DP&L	Exhibit Number	Exhibit	Location
X	X	4(t)	Bond Purchase and Covenants Agreement, dated as of August 3, 2015, among The Dayton Power and Light Company, SunTrust Bank, as Administrative Agent, and the several lenders from time to time party thereto	Exhibit 4.5 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
X		10(a)	Credit Agreement, dated as of July 31, 2015, among DPL Inc., U.S. Bank National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and an L/C Issuer, PNC Bank, National Association, as Syndication Agent and an L/C Issuer, Bank of America, N.A., as Documentation Agent and an L/C Issuer, and the other lenders party to the Credit Agreement	Exhibit 10.1 to Report on Form 8-K filed August 6, 2015 (File No. 1-9052)
X		10(b)	Guaranty Agreement, dated as of July 31, 2015, between DPL Energy, LLC and U.S. Bank National Association, as Administrative Agent	Exhibit 10.2 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
X		10(c)	Pledge Agreement, dated as of July 31, 2015, between DPL Inc. and U.S. Bank National Association, as Collateral Agent	Exhibit 10.3 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
X		10(d)	Open-end Mortgage, Security Agreement, Assignment of Leases and Rents, and Fixture Filing, dated as of July 31, 2015, made by DPL Energy LLC to U.S. Bank National Association, as Collateral Agent and Mortgagee	Exhibit 10.4 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
X	X	10(e)	Credit Agreement, dated as of July 31, 2015, among The Dayton Power and Light Company, PNC Bank, National Association, as Administrative Agent, Swing Line Lender and an L/C Issuer, Fifth Third Bank, as Syndication Agent and an L/C Issuer, Bank of America, N.A., as Documentation Agent and an L/C Issuer, and the other lenders party to the Credit Agreement	Exhibit 10.5 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
X		10(f)	Open-End Leasehold Mortgage, Security Agreement, Assignment of Leases and Rents, and Fixture Filing from DPL Energy, LLC to U.S. Bank National Association, dated as of October 29, 2015	Exhibit 10(a) to Report on Form 10-Q for the quarter ended September 30, 2015 (File No. 1-9052)
X		31(a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(a)
X		31(b)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(b)
	X	31(c)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(c)
	X	31(d)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(d)
X		32(a)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(a)

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DPL	DP&L	Exhibit Number	Exhibit	Location
X		32(b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(b)
	X	32(c)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(c)
	X	32(d)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(d)
X	X	101.INS	XBRL Instance	Furnished herewith as Exhibit 101.INS
X	X	101.SCH	XBRL Taxonomy Extension Schema	Furnished herewith as Exhibit 101.SCH
X	X	101.CAL	XBRL Taxonomy Extension Calculation Linkbase	Furnished herewith as Exhibit 101.CAL
X	X	101.DEF	XBRL Taxonomy Extension Definition Linkbase	Furnished herewith as Exhibit 101.DEF
X	X	101.LAB	XBRL Taxonomy Extension Label Linkbase	Furnished herewith as Exhibit 101.LAB
X	X	101.PRE	XBRL Taxonomy Extension Presentation Linkbase	Furnished 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.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, we have not filed as an exhibit to our Form 10-K certain instruments with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of us and our subsidiaries on a consolidated basis, but we hereby agree to furnish to the SEC on request any such instruments.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, DPL Inc. and The Dayton Power and Light Company have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized

	DPL Inc.
March 16, 2016	/s/ Kenneth J. Zagzebski
	Kenneth J. Zagzebski
	President and Chief Executive Officer
	(principal executive officer)
	The Dayton Power and Light Company
March 16, 2016	/s/ Thomas A. Raga
	Thomas A. Raga
	President and Chief Executive Officer
	(principal executive officer)

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