Filed Pursuant to Rule 424(b)(3)
Registration No. 333-204572

PROSPECTUS

DPL Inc.

Offer to Exchange
6.750% Senior Notes due 2019
for
New 6.75% Senior Notes Due 2019

We are offering to exchange up to $200,000,000 of our new registered 6.75% Senior Notes due 2019 (the “new notes”) for up to $200,000,000 of our existing unregistered 6.75% Senior Notes due 2019 (the “old notes”). The terms of the new notes are identical in all material respects to the terms of the old notes, except that the new notes have been registered under the Securities Act of 1933, as amended (the “Securities Act”), and the transfer restrictions and registration rights relating to the old notes do not apply to the new notes. The new notes will represent the same debt as the old notes and we will issue the new notes under the same indenture.

To exchange your old notes for new notes:

· you are required to make the representations described on page 4 to us; and

· you should read the section called “The Exchange Offer” starting on page 102 for further information on how to exchange your old notes for new notes.

The exchange offer will expire at 11:59 P.M. New York City time on July 13, 2015 unless it is extended.

See “Risk Factors” beginning on page 8 of this prospectus for a discussion of risk factors that should be considered by you prior to tendering your old notes in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of the securities to be issued in the exchange offer or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

June 15, 2015

Table of Contents
Page
Summary	1
Risk Factors	8
Cautionary Note Regarding Forward-Looking Statements	24
Use of Proceeds	25
Ratio of Earnings to Fixed Charges	26
Capitalization	27
Selected Consolidated Financial and Other Data	28
Management’s Discussion and Analysis of Results of Operations and Financial Condition	29
Business	74
Description of the Notes	82
The Exchange Offer	102
U.S. Federal Income Tax Consequences of the Exchange Offer	109
Plan of Distribution	109
Validity of Securities	110
Experts	110
Where You Can Find More Information	110
Index to Financial Statements	F-1

We have not authorized anyone to provide you with any information other than that contained in this prospectus or to which we have referred you. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus is based on information provided by us and by other sources that we believe are reliable. We cannot assure you that this information is accurate or complete. This prospectus summarizes certain documents and other information and we refer you to them for a more complete understanding of what we discuss in this prospectus. In making an investment decision, you must rely on your own examination of our company and the terms of the offering and the notes, including the merits and risks involved.

We are not making any representation to any purchaser of the notes regarding the legality of an investment in the notes by such purchaser under any legal investment or similar laws or regulations. You should not consider any information in this prospectus to be legal, business or tax advice. You should consult your own attorney, business advisor and tax advisor for legal, business and tax advice regarding an investment in the notes.

Neither the Securities and Exchange Commission (“SEC”) nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

NOTICE TO NEW HAMPSHIRE RESIDENTS

NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES ANNOTATED, 1995, AS AMENDED, WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE OF NEW HAMPSHIRE THAT ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GAVE APPROVAL TO, ANY PERSON, SECURITY, OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY

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PROSPECTIVE PURCHASER, CUSTOMER, OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.

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GLOSSARY OF TERMS

The following select abbreviations or acronyms are used in this prospectus:

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 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
AMI	Advanced Metering Infrastructure
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
BTU	British Thermal Units
CFTC	Commodity Futures Trading Commission
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CCEM	Customer Conservation and Energy Management
CO2	Carbon Dioxide
ComEd	Commonwealth Edison
CRES	Competitive Retail Electric Service
CSAPR	Cross-State Air Pollution Rule
CWA	Clean Water Act
Dark spread	A common metric used to estimate returns over fuel costs of coal-fired electric generating units
DPL	DPL Inc.

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Abbreviation or Acronym  Definition 

DPLE	DPL Energy, LLC, a wholly-owned subsidiary of DPL that owns and operates peaking generation facilities from which it makes wholesale sales
DPLER	DPL Energy Resources, Inc., a wholly-owned subsidiary of DPL which sells competitive electric energy and other energy services
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 in Ohio (Duke Energy Ohio, Inc.)
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
FTR	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

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Abbreviation or Acronym  Definition 

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, and formerly a wholly-owned subsidiary of DPLER (sold April 1, 2015)
Merger	The merger of DPL and Dolphin Sub, Inc. (a wholly-owned subsidiary of AES) in accordance with the terms of the Merger agreement. At the Merger date, Dolphin Sub, Inc. was merged into DPL, leaving DPL as the surviving company. As a result of the Merger, DPL became a wholly-owned subsidiary of AES.
Merger agreement	The Agreement and Plan of Merger dated April 19, 2011 among DPL, AES and Dolphin Sub, Inc., a wholly-owned subsidiary of AES, whereby AES agreed to acquire DPL for $30 per share in a cash transaction valued at approximately $3.5 billion plus the assumption of $1.2 billion of existing debt. Upon closing, 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., a wholly-owned subsidiary of AES
MRO	Market Rate Option, a market-based plan that a utility may file with PUCO to establish SSO rates pursuant to Ohio law
MTM	Mark to Market
MVIC	Miami Valley Insurance Company, a wholly-owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries and, in some cases, insurance services to partner companies relative to jointly-owned facilities operated by DP&L
MW	Megawatt
MWh	Megawatt hour
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

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Abbreviation or Acronym  Definition 

NOV	Notice of Violation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
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 is PJM’s capacity construct. The purpose of the RPM is to enable PJM to obtain sufficient resources to reliably meet the needs of electric customers within the PJM footprint.  Under the RPM construct, PJM procures capacity, through a multi-auction structure, on behalf of the load serving entities to satisfy the load obligations.  There are three RPM 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.
RTO	Regional Transmission Organization

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Abbreviation or Acronym  Definition 

SB 221	Ohio Senate Bill 221, 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.
SCR	Selective Catalytic Reduction
SEC	Securities and Exchange Commission
SECA	Seams Elimination Charge Adjustment
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
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
VRDN	Variable Rate Demand Note

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Summary

This summary highlights information contained elsewhere in this prospectus. This summary may not contain all of the information that may be important to you. You should read this entire prospectus before making a decision to exchange your old notes for new notes, including the section entitled “Risk Factors” beginning on page 8 of this prospectus.

Unless otherwise indicated or the context otherwise requires, the terms “DPL,” “we,” “our,” “us,” and “the Company” refer to DPL Inc., including all of its subsidiaries and affiliates, collectively.

Our Company

We are a diversified regional energy company that serves retail customers in West Central Ohio and Illinois through our subsidiaries, DP&L, which comprises our Utility segment, and DPL Energy Resources, Inc. (“DPLER”), which comprises our Competitive Retail segment.

DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail services are still regulated. DP&L has the exclusive right to provide such services to its approximately 516,000 customers located in West Central Ohio. Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at five coal-fired power stations. Beginning in 2014, DP&L no longer provides 100% of the generation for its SSO customers. 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 prices of electricity and capacity. DP&L sells any excess energy and capacity into the wholesale market. DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER’s retail customers.

DPLER sells competitive retail electric service, under contract, to residential, commercial, industrial and governmental customers. DPLER has approximately 163,000 customers currently located throughout Ohio. Approximately 124,000 of DPLER’s customers are also electric distribution customers of DP&L. DPLER does not have any transmission or generation assets and all of DPLER’s electric energy is purchased from DP&L to meet its sales obligations.

Our 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 DP&L and DPL’s other subsidiaries. We also have a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors. All of our subsidiaries are wholly-owned. DP&L does not have any subsidiaries.

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 recoveries in customer rates relate to expected future costs.

We strive to achieve disciplined growth in energy margins while limiting volatility in both cash flows and earnings, and to achieve stable, long-term growth through efficient operations and strong customer and regulatory relations. More specifically, our strategy is to match energy supply with load, or customer demand, to help maximize profits while effectively managing exposure to movements in energy and fuel prices and utilizing the transmission and distribution assets that transfer electricity at the most efficient cost, and to maintain the highest level of customer service and reliability.

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DPL Inc. was incorporated under the laws of the State of Ohio in 1985. Our principal executive office is located at 1065 Woodman Drive, Dayton, Ohio, 45432, and its telephone number is (937) 224-6000.  Our website address is http://www.dplinc.com.  Material contained on our website is not part of and is not deemed to be a part of this prospectus.

DPL Inc. is a wholly owned indirect subsidiary of The AES Corporation (“AES”). AES is a global power company. AES’s executive offices are located at 4300 Wilson Boulevard, Arlington, VA, 22203 and its telephone number is (703) 522-1315.

The names “DPL,” “The Dayton Power & Light Company” and various other names contained herein are DPL owned trademarks, service marks or trade names.  The name “AES” is an AES owned trademark, service mark or trade name. All other trademarks, trade names or service marks appearing herein are owned by their respective holders.

Recent Developments

On April 1, 2015, we completed the sale of MC Squared, a Chicago-based retail electricity supplier that serves approximately 108,000 customers in Northern Illinois, which was previously included in our Competitive Retail Segment as a subsidiary of DPLER.

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The Exchange Offer 

Securities Offered	We are offering up to $200,000,000 aggregate principal amount of new 6.75% Senior Notes due 2019 (the “new notes”), which will be registered under the Securities Act.
The Exchange Offer	We are offering to issue the new notes in exchange for a like principal amount of your old notes. We are offering to issue the new notes to satisfy our obligations contained in the registration rights agreement entered into when the old notes were sold in transactions permitted by Rule 144A and Regulation S under the Securities Act and therefore not registered with the SEC. For procedures for tendering, see “The Exchange Offer.”
Tenders, Expiration Date, Withdrawal	The exchange offer will expire at 11:59 P.M. New York City time on July 13, 2015 unless it is extended. If you decide to exchange your old notes for new notes, you must acknowledge that you are not engaging in, and do not intend to engage in, a distribution of the new notes. If you decide to tender your old notes in the exchange offer, you may withdraw them at any time prior to July 13, 2015. If we decide for any reason not to accept any old notes for exchange, your old notes will be returned to you without expense to you promptly after the exchange offer expires. You may only exchange old notes in denominations of $2,000 and integral multiples of $1,000 in excess thereof.
U.S. Federal Income Tax Consequences	Your exchange of old notes for new notes in the exchange offer will not result in any income, gain or loss to you for U.S. federal income tax purposes. See “U.S. Federal Income Tax Consequences of the Exchange Offer.”
Use of Proceeds	We will not receive any proceeds from the issuance of the new notes in the exchange offer.
Exchange Agent	U.S. Bank National Association is the exchange agent for the exchange offer.
Failure to Tender Your Old Notes	If you fail to tender your old notes in the exchange offer, you will not have any further rights under the registration rights agreement, including any right to require us to register your old notes or to pay you additional interest or liquidated damages. All untendered old notes will continue to be subject to the restrictions on transfer set forth in the old notes and in the indenture. In general, the old notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and

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applicable state securities laws. We do not currently anticipate that we will register such untendered old notes under the Securities Act and, following this exchange offer, will be under no obligation to do so.

You will be able to resell the new notes without registering them with the SEC if you meet the requirements described below.

Based on interpretations by the SEC’s staff in no-action letters issued to third parties, we believe that new notes issued in exchange for the old notes in the exchange offer may be offered for resale, resold or otherwise transferred by you without registering the new notes under the Securities Act or delivering a prospectus, unless you are a broker-dealer receiving securities for your own account, so long as:

· you are not one of our “affiliates,” which is defined in Rule 405 of the Securities Act;

· you acquire the new notes in the ordinary course of your business;

· you do not have any arrangement or understanding with any person to participate in the distribution of the new notes; and

· you are not engaged in, and do not intend to engage in, a distribution of the new notes.

If you are an affiliate of DPL, or you are engaged in, intend to engage in or have any arrangement or understanding with respect to, the distribution of new notes acquired in the exchange offer, you (1) should not rely on our interpretations of the position of the SEC’s staff and (2) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

If you are a broker-dealer and receive new notes for your own account in the exchange offer and/or in exchange for old notes that were acquired for your own account as a result of market-making or other trading activities:

· you must represent that you do not have any arrangement or understanding with us or any of our affiliates to distribute the new notes;

· you must acknowledge that you will deliver a prospectus in connection with any resale of the new notes you receive from us in the exchange offer; the letter of transmittal states that by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an “underwriter” within the meaning of the Securities Act; and

· you may use this prospectus, as it may be amended or supplemented from time to time, in connection with the resale of new notes received in exchange for old notes acquired by you as a result of market-making or other trading activities.

For a period of 90 days after the expiration of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any resale described above.

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Summary Description of the Notes

The terms of the new notes and the old notes are identical in all material respects, except that the new notes have been registered under the Securities Act, and the transfer restrictions and registration rights relating to the old notes do not apply to the new notes. The new notes will represent the same debt as the old notes and will be governed by the same indenture under which the old notes were issued.

Issuer	DPL Inc.
Notes Offered	$200,000,000 aggregate principal amount
Maturity	October 1, 2019
Interest Payment Dates	The new notes will bear interest at an annual rate equal to 6.75%. Interest on the notes will be paid on each April 1 and October 1.
Record Dates	The regular record date for each interest payment date for the notes will be the March 15 or September 15 prior to such interest payment date.
Denominations	Minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.
Ranking	The notes are our unsecured and unsubordinated obligations and will rank:
	- equal in right of payment with all of our other senior unsecured debt;
	- effectively junior in right of payment to (a) our secured debt, if any, to the extent of the value of the assets securing such debt and (b) the debt and other liabilities (including trade payables) of our subsidiaries; and
	- senior in right of payment to our subordinated debt (if any).
	As of March 31, 2015
	- We had, on a consolidated basis, approximately $1,303.8 million of senior unsecured debt, $859.4 million of secured debt and no subordinated debt outstanding;
	- We had, on an unconsolidated basis, approximately $1,270.0 million of senior unsecured debt, and no secured debt or subordinated debt outstanding; and
	- Our subsidiaries had approximately $2,087.6 million of debt and other liabilities, including trade payables, outstanding.
	The indenture under which the new notes will be issued contains no restrictions on the amount of additional unsecured indebtedness that we may incur or the amount

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	of  indebtedness (whether secured or unsecured) that our subsidiaries may incur (subject to compliance with the Limitation on Liens covenant in the case of secured debt).
	There will be no recourse against AES with respect to the notes offered hereby.
Optional Redemption	Prior to September 1, 2019 (one month before the maturity date), we may redeem some or all of the new notes at a redemption price equal to the greater of:
	(1)   100% of the principal amount of the notes being redeemed; or
	(2)   the sum of the present values of the remaining scheduled payments of principal of and interest on the notes being redeemed discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined herein) plus 50.0 basis points;
	plus, for (1) or (2) above, whichever is applicable, accrued interest on such notes to, but excluding, the date of redemption.
	At any time on or after September 1, 2019, we may redeem some or all of the new notes at 100% of the principal amount of the notes being redeemed plus accrued and unpaid interest to, but excluding, the date of redemption. See “Description of the Notes—Optional Redemption.”
Change of Control	Upon the occurrence of a change of control triggering event (as described in “Description of the Notes—Repurchase at the Option of Holders”), you may require the repurchase of some or all of your notes at 101% of their principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.
Covenants	The indenture governing the notes contains covenants that, among other things, limit our ability and, in the case of restrictions on liens, the ability of our significant subsidiaries to:
	- create certain liens on assets and properties; and
	- consolidate or merge, or convey, transfer or lease substantially all of our consolidated properties and assets.
	The indenture that governs the notes also restricts our ability to make dividends or distributions.
	These covenants are subject to important exceptions and qualifications, which are described in “Description

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	of Notes—Covenants.” The indenture does not in any way restrict or prevent DP&L or any other DPL subsidiary from incurring indebtedness (subject to compliance with the Limitation on Liens covenant in the case of secured debt).
Book-Entry Form	The notes will be issued in registered book-entry form represented by one or more global notes to be deposited with or on behalf of The Depository Trust Company (“DTC”) or its nominee. Transfers of the notes will be effected only through the facilities of DTC. Beneficial interests in the global notes may not be exchanged for certificated notes except in limited circumstances. See “Description of Notes—Global Notes.”
Trustee, Registrar and Paying Agent	U.S. Bank National Association.
Governing Law	The indenture and the notes are governed by the laws of the State of New York.
Risk Factors	You should carefully consider all of the information contained in this prospectus before deciding to tender your old notes in the exchange offer. In particular, we urge you to carefully consider the information set forth under “Risk Factors” herein for a discussion of risks and uncertainties relating to us, our business and the new notes offered hereby.

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Risk Factors

If any of the following risks occur, our business, results of operations or financial condition could be materially adversely affected. You should also read the section captioned “Cautionary Note Regarding Forward-Looking Statements” for a discussion of what types of statements are forward-looking as well as the significance of such statements in the context of this prospectus.

Risks Related to the Exchange Offer

If you choose not to exchange your old notes in the exchange offer, the transfer restrictions currently applicable to your old notes will remain in force and the market price of your old notes could decline.

If you do not exchange your old notes for new notes in the exchange offer, then you will continue to be subject to the transfer restrictions on the old notes as set forth in the offering memorandum distributed in connection with the private offering of the old notes. In general, the old notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement entered into in connection with the private offering of the old notes, we do not intend to register resales of the old notes under the Securities Act.  The tender of old notes under the exchange offer will reduce the principal amount of the old notes outstanding, which may have an adverse effect upon, and increase the volatility of, the market price of the old notes due to reduction in liquidity.

You must follow the exchange offer procedures carefully in order to receive the new notes.

If you do not follow the procedures described in this prospectus, you will not receive any new notes. If you want to tender your old notes in exchange for new notes, you will need to contact a DTC participant to complete the book-entry transfer procedures, or otherwise complete and transmit a letter of transmittal, in each case described under “The Exchange Offer,” prior to the expiration date, and you should allow sufficient time to ensure timely completion of these procedures to ensure delivery. No one is under any obligation to give you notification of defects or irregularities with respect to tenders of old notes for exchange. For additional information, see the section captioned “The Exchange Offer” in this prospectus.

There are state securities law restrictions on the resale of the new notes.

In order to comply with the securities laws of certain jurisdictions, the new notes may not be offered or resold by any holder, unless they have been registered or qualified for sale in such jurisdictions or an exemption from registration or qualification is available and the requirements of such exemption have been satisfied. We currently do not intend to register or qualify the resale of the new notes in any such jurisdictions. However, generally an exemption is available for sales to registered broker-dealers and certain institutional buyers. Other exemptions under applicable state securities laws also may be available.

Risks Related to the Notes

We are a holding company and parent of DP&L and other subsidiaries. Our cash flow is dependent on the operating cash flows of DP&L and our other subsidiaries and their ability to pay cash to us. Our subsidiaries will not guarantee the notes and will not be restricted under the indenture that will govern the notes.

We are a holding company and our investments in our subsidiaries are our primary assets. Our subsidiaries are separate and distinct legal entities and, unless they have expressly guaranteed any of our indebtedness, have no obligation, contingent or otherwise, to pay any amounts due pursuant to such debt or to make any funds available whether by dividends, fees, loans or other payments. In addition, under certain circumstances, legal, regulatory or contractual restrictions may limit our ability to obtain cash from our subsidiaries. None of our subsidiaries are guaranteeing, or are otherwise obligated with respect to, the notes offered hereby.

A significant portion of our business is conducted by our subsidiary, DP&L. As such, our cash flow is dependent on the operating cash flows of DP&L and its ability to pay cash to us. DP&L’s governing documents

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contain certain limitations on the ability to declare and pay dividends to us while preferred stock is outstanding. Certain of DP&L’s debt agreements also contain limits with respect to the ability of DP&L to loan or advance funds to us. In addition, DP&L is regulated by the PUCO that possesses broad oversight powers to ensure that the needs of utility customers are being met. 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. While we are not currently aware of any plans to do so, the PUCO could attempt to impose restrictions on the ability of DP&L to pay cash to us pursuant to these broad powers. A significant limitation on DP&L’s ability to pay dividends or loan or advance funds to us would have a material adverse impact on our results of operations, financial condition and cash flows, and its ability to make interest and principal payments on the notes and its other indebtedness.

Any right we have to receive any assets of any of our subsidiaries upon any liquidation, dissolution, winding up, receivership, reorganization, assignment for the benefit of creditors, marshaling of assets and liabilities or any bankruptcy, insolvency or similar proceedings (and the consequent right of the holders of our indebtedness to participate in the distribution of, or to realize proceeds from, those assets) will be effectively subordinated to the claims of any such subsidiary’s creditors (including trade creditors and holders of debt issued by such subsidiary).

The notes will be effectively subordinated to the liabilities of our subsidiaries.

Our subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due on the notes offered hereby or to make any funds available therefor, whether by dividends, fees, loans or other payments. Any right we have to receive any assets of any of our subsidiaries upon any liquidation, dissolution, winding up, receivership, reorganization, assignment for the benefit of creditors, marshaling of assets and liabilities or any bankruptcy, insolvency or similar proceedings (and the consequent right of the holders of our indebtedness to participate in the distribution of, or to realize proceeds from, those assets) will be effectively subordinated to the claims of any such subsidiary’s creditors (including trade creditors and holders of debt issued by such subsidiary). Accordingly, the notes will be effectively subordinated to all liabilities of our existing or future subsidiaries. At March 31, 2015, our subsidiaries had approximately $2,087.6 million of outstanding debt and other liabilities, including trade payables. The indenture governing the notes will not limit the ability of our subsidiaries to incur additional indebtedness or other liabilities (subject to the Limitation on Liens covenant in the case of secured debt).

The notes will be effectively subordinated to our and DP&L’s secured debt.

The notes will be our unsecured general obligations, and therefore will be effectively subordinated to all of our secured debt, if any, and all of the secured debt of DP&L to the extent of the value of the assets securing such debt. In the event of any distribution or payment of our assets in any foreclosure, dissolution, winding-up, liquidation or reorganization, or other bankruptcy proceeding, our secured creditors will have a superior claim to the applicable collateral. As of March 31, 2015, on a consolidated basis, we had a total of approximately $859.4 million of secured debt outstanding. The indenture that will govern the notes limits but does not prohibit us from incurring secured debt, and there are significant exceptions to this covenant. See ‘‘Description of the Notes—Covenants—Limitations on Liens.’’

In addition, if we default under any of our existing or future secured indebtedness, the holders of such indebtedness could declare all of the funds borrowed thereunder, together with accrued interest, immediately due and payable. If we are unable to repay such indebtedness, the holders of such indebtedness could foreclose on the pledged assets to the exclusion of the holders of the notes, even if an event of default exists under the indenture governing the notes at such time. In any such event, because the notes will not be secured by any of our assets, it is possible that there would be no assets remaining from which your claims could be satisfied or, if any assets remained, they might be insufficient to satisfy your claims in full.

We may not be able to repurchase the notes upon a change of control.

Upon a ‘‘Change of Control Triggering Event’’ (as defined under ‘‘Description of the Notes—Repurchase at the Option of Holders’’), we will be required to offer to repurchase all outstanding notes at 101% of their principal amount plus accrued and unpaid interest. The source of funds for any such purchase of the notes will be our available cash or cash generated from our subsidiaries’ operations or other sources, including

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borrowings, issuance of additional debt, sales of assets or sales of equity. The obligations under our other indebtedness may also be accelerated in such circumstances. We may not be able to satisfy our obligations to repurchase the notes upon a Change of Control Triggering Event because we may not have sufficient financial resources to purchase all of the notes that are tendered upon a Change of Control Triggering Event.

It is also possible that the events that constitute a Change of Control Triggering Event may also be events of default under the agreements governing our other debt. These events may permit such lenders to accelerate the indebtedness outstanding thereunder. If we are required to repurchase the notes pursuant to a change of control offer and repay certain amounts outstanding under our other debt if such indebtedness is accelerated, we would probably require third-party financing. We cannot be sure that we would be able to obtain third-party financing on acceptable terms, or at all. If our other debt is not paid, the lenders thereunder may seek to enforce security interests in the collateral securing such indebtedness, thereby limiting our ability to raise cash to purchase the notes, and reducing the practical benefit of the offer to purchase provisions to the holders of the notes. Any future debt agreements may contain similar provisions.

The terms of the indenture governing the notes offered hereby provide only limited protection against significant corporate events and other actions we may take that could adversely impact your investment in the notes.

While the indenture governing the notes offered hereby contains terms intended to provide protection to the holders of the notes upon the occurrence of certain events involving significant corporate transactions, such terms are limited and may not be sufficient to protect your investment in the notes.

The definition of the term Change of Control does not cover a variety of transactions (such as acquisitions by us or recapitalizations) that could negatively affect the value of your notes. In addition, both a Change of Control and a Rating Event (as defined in ‘‘Description of the Notes’’) are required for a Change of Control Triggering Event to take place. If we were to enter into a significant corporate transaction that would negatively affect the value of the notes but would not constitute a Change of Control Triggering Event, we would not be required to offer to repurchase your notes prior to their maturity. Furthermore, the indenture governing the notes offered hereby will not require us to maintain any financial ratios or specific levels of net worth, sales, income, cash flow or liquidity.

Holders of the notes may not be able to determine when a change of control giving rise to their right to have the notes repurchased has occurred following a sale of ‘‘substantially all’’ of our assets.

One of the circumstances under which a change of control may occur is upon the sale or disposition of all or substantially all of our assets. There is no precise established definition of the phrase ‘‘substantially all’’ under applicable law, and the interpretation of that phrase will likely depend upon particular facts and circumstances. Accordingly, the ability of a holder of notes to require us to repurchase its notes as a result of a sale of less than all our assets to another person may be uncertain.

We may incur additional indebtedness, which may affect our financial health and our ability to repay the notes.

As of March 31, 2015, on a consolidated basis, we had $2,163.2 million of indebtedness, $859.4 million of which was secured indebtedness. This level of indebtedness and the related security could have important consequences, including the following:

· increase our vulnerability to general adverse economic and industry conditions;

· place us at a competitive disadvantage compared to our competitors that are less leveraged;

· require us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund other corporate purposes;

· limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

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· limit, along with the financial and other restrictive covenants in our indebtedness, among other things, our ability to borrow additional funds, as needed.

A high level of indebtedness increases the risk that we default on our debt obligations, including the notes. We and/or our subsidiaries expect to incur additional debt in the future, subject to the terms of debt agreements and regulatory approvals. To the extent we become more leveraged, the risks described above would increase. Further, our actual cash requirements in the future may be greater than expected. Accordingly, our cash flow from operations may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance our debt, including the notes, as it becomes due.

A court could deem the obligations evidenced by the notes to be a fraudulent conveyance.

The incurrence of the indebtedness under the notes, and any payment of cash dividends and other payments in respect of our equity interests, are subject to review under relevant federal and state fraudulent conveyance laws in a bankruptcy or reorganization case or lawsuit by or on behalf of our creditors. Under these laws, if a court were to find at the time the notes were issued that (1) we incurred such indebtedness and made such payments with the intent of hindering, delaying or defrauding current or future creditors or (2) we received less than reasonably equivalent value or fair consideration for incurring such indebtedness and, in the case of (2) only, one of the following is also true at the time thereof:

· were insolvent or rendered insolvent by reason of such incurrence,

· were engaged in a business or transaction for which our remaining assets constituted unreasonably small capital, or

· intended to incur, or believed that we would incur, debts beyond our ability to pay such debts as they mature (as all of the foregoing terms are defined or interpreted under the relevant fraudulent transfer or conveyance statutes),

then the court could void or otherwise decline to enforce the notes.

In addition, any payment by us pursuant to the notes made at a time we are found to be insolvent could be voided and required to be returned to us or to a fund for the benefit of our creditors if such payment is made to an insider within a one-year period prior to a bankruptcy filing or within 90 days for any outside party and such payment would give the creditors more than such creditors would have received in a distribution under Title 11 of the United States Code, as amended (the ‘‘Bankruptcy Code’’).

The measure of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a company would be considered insolvent if:

· the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;

· if the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they became absolute and matured; or

· it could not pay its debts as they became due.

We believe that both prior to and after giving effect to this offering we will not be insolvent, will not have unreasonably small capital for our business and will not have incurred debts beyond our ability to pay such debts as they mature. We cannot assure you, however, as to what standard a court would apply in making these determinations or that a court would agree with our conclusions in this regard or, regardless of the standard that a court uses, that the issuance of the notes would not be voided or otherwise enforced. If a court voided our obligations under the notes, holders of the notes would cease to be our creditors and likely have no source from

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which to recover amounts due under the notes. In addition, a court could void any payment by us pursuant to the notes and require any payment to be returned, or to be paid to a fund for the benefit of our creditors.

Finally, as a court of equity, the bankruptcy court may subordinate the claims in respect of the notes to the claims of other creditors under the principle of equitable subordination, if the court determines that: (i) the holder of the notes engaged in some type of inequitable conduct to the detriment of other creditors; (ii) such inequitable conduct resulted in injury to other creditors or conferred an unfair advantage upon the holder of the notes; and (iii) equitable subordination is not inconsistent with the provisions of the Bankruptcy Code.

If we file a bankruptcy petition, or if a bankruptcy petition is filed against us, you may receive a lesser amount for your claim under the notes than you would have been entitled to receive under the indenture governing the notes.

If we file a bankruptcy petition under the Bankruptcy Code after the issuance of the notes, or if such a bankruptcy petition is filed against us, your claim against us for the principal amount of your notes may be limited to an amount equal to:

· the original issue price for the notes; and

· the portion of original issue discount that does not constitute ‘‘unmatured interest’’ for purposes of the Bankruptcy Code.

Any original issue discount that was not amortized as of the date of any bankruptcy filing would constitute unmatured interest. Accordingly, under these circumstances, you may receive a lesser amount than you would have been entitled to receive under the terms of the indenture governing the notes, even if sufficient funds are available.

AES beneficially owns all of our issued and outstanding equity, and may take actions that conflict with your interests.

AES beneficially owns all of our issued and outstanding equity interests. As a result of this equity ownership, AES has the power to direct votes and the election of our board of directors, as well as transactions involving a potential change of control of DPL. The interests of AES could conflict with your interests as a holder of the notes. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of AES as the beneficial owner of all of our equity might conflict with your interests as a holder of the notes. AES may also have an interest in pursuing acquisitions, divestitures, financings or other transactions that would enhance the value of their equity position in our company. Corporate opportunities may arise in the area of potential competitive business activities that may be attractive to us as well as to AES or its affiliates, including through potential acquisitions by AES or its affiliates of competing businesses. Any competition could intensify if an affiliate or subsidiary of AES were to enter into or acquire a business similar to our business. Further, AES has no obligation to provide us, directly or indirectly, with any equity or debt financing.

Credit rating downgrades could adversely affect the trading price of the notes.

The trading price for the notes may be affected by our credit rating and the credit rating of AES. Credit ratings are continually revised. Any downgrade in our credit rating or the credit rating of AES could adversely affect the trading price of the notes or the trading markets for the notes to the extent trading markets for the notes develop. Credit ratings are not recommendations to purchase, hold or sell the notes. Additionally, credit ratings may not reflect the potential effect of risks relating to the structure or marketing of the notes.

Any future lowering of our ratings or the rating of AES likely would make it more difficult or more expensive for us to obtain additional debt financing. If any credit rating initially assigned to the notes is subsequently lowered or withdrawn for any reason, you may not be able to resell your notes without a substantial discount.

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Risks Related to Our Business

Our customers have the opportunity to select alternative electric generation service providers, as permitted by Ohio legislation.

Customers can elect to buy generation service from a PUCO-certified CRES provider offering services to customers in DP&L’s service territory. DPLER, our wholly-owned subsidiary, is one of those PUCO-certified CRES providers. Unaffiliated CRES providers also have been certified to provide energy in DP&L’s service territory. Customer switching from DP&L to DPLER reduces our revenues since the generation rates charged by DPLER are less than the SSO rates charged by DP&L. Increased competition by unaffiliated CRES providers in DP&L’s service territory for retail generation service could result in the loss of existing customers and reduced revenues and increased costs to retain or attract customers. Decreased revenues and increased costs due to continued customer switching and customer loss in 2015 could have a material adverse effect on our results of operations, financial condition and cash flows. As discussed below in “Business—Competition and Regulation”, beginning January 1, 2016, customer switching will have no effect on DP&L. The following are some of the factors that could result in increased switching by customers to PUCO-certified CRES providers in the future:

· low wholesale price levels have led, and may continue to lead, to existing CRES providers becoming more active in our service territory,

· additional CRES providers entering our territory, and we may experience increased customer switching through governmental aggregation, where a municipality may contract with a CRES provider to provide generation service to the customers located within the municipal boundaries.

The operation and performance of our facilities are subject to various events and risks that could negatively affect our business.

The operation and performance of our generation, transmission and distribution facilities and equipment is subject to various events and risks, such as the potential breakdown or failure of equipment, processes or facilities, fuel supply or transportation disruptions, the loss of cost-effective disposal options for solid waste generated by our facilities (such as coal ash and gypsum), accidents, injuries, labor disputes or work stoppages by employees, operator error, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, performance below expected or required levels, weather-related and other natural disruptions, vandalism, events occurring on the systems of third parties that interconnect to and affect our system and the increased maintenance requirements, costs and risks associated with our aging generation units. Our results of operations, financial condition and cash flows could have a material adverse effect due to the occurrence or continuation of these events.

Diminished availability or performance of our transmission and distribution facilities could result in reduced customer satisfaction and regulatory inquiries and fines, which could have a material adverse effect on our results of operations, financial condition and cash flows. Operation of our owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and efficiency levels and likely result in lost revenues and increased expenses that could have a material adverse effect on our results of operations, financial condition and cash flows. In particular, since nearly 42% of our base-load generation is derived from co-owned generation stations operated by our co-owners, poor operational performance by our co-owners, misalignment of co-owners interests or lack of control over costs (such as fuel costs) incurred at these stations could have an adverse effect on us. In addition, our co-owners have either taken steps to sell their co-ownership interest in these co-owned generation stations or have expressed an interest in selling such generation facilities. Any sale of these co-owned generation stations by a co-owner to a third party could enhance the risk of a misalignment of interests, lack of cost control and other operational failures. We have constructed and placed into service FGD facilities at our base-load generating stations. If there is significant operational failure of the FGD equipment at the generating stations, we may not be able to meet emission requirements at some of our generating stations or it may require us to burn more expensive types of coal or procure additional emission allowances. These events could result in a substantial increase in our operating costs. Depending on the degree, nature, extent, or willfulness of any failure to comply

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with environmental requirements, including those imposed by any consent decrees, such non-compliance could result in the imposition of penalties or the shutting down of the affected generating stations, which could have a material adverse effect on our results of operations, financial condition and cash flows.

Asbestos and other regulated substances are, and may continue to be, present at our facilities. We have been named as a defendant in asbestos litigation, which at this time is not material to us. The continued presence of asbestos and other regulated substances at these facilities could result in additional litigation being brought against us, which could have a material adverse effect on our results of operations, financial condition and cash flows.

The costs we can recover and the return on capital we are permitted to earn for certain aspects of our business are regulated and governed by the laws of Ohio and the rules, policies and procedures of the PUCO.

On May 1, 2008, SB 221, an Ohio electric energy bill, was signed by the Governor of Ohio and became effective July 31, 2008. This law, among other things, required all Ohio distribution utilities to file either an ESP or MRO, and established a significantly excessive earnings test for Ohio public utilities that compares the utility’s earnings to the earnings of other companies with similar business and financial risks. The PUCO order in the 2012 ESP case changed DP&L’s rate structure and the ability to recover certain costs which will affect our results of operations, cash flows and financial condition. DP&L’s ESP and certain filings made by us in connection with this plan are further discussed under Ohio Retail Rates in “Business¾Competition and Regulation.”

In Ohio, retail generation rates are no longer subject to cost-based regulation, while the distribution and transmission businesses are still regulated. Even though rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCO will agree that all of our costs have been prudently incurred or are recoverable. There is also no assurance that the regulatory process in which rates are determined will always result in rates that will produce a full or timely recovery of our costs and permitted rates of return. Accordingly, the revenue DP&L receives may or may not match its expenses at any given time. Therefore, DP&L is subject to prevailing market prices for electricity and would not necessarily be able to charge rates that produce timely or full recovery of its expenses. Changes in, or reinterpretations of, the laws, rules, policies and procedures that set electric rates, permitted rates of return, changes in DP&L’s rate structure, regulations regarding ownership of generation assets, transition to a competitive bid structure to supply retail generation service to SSO customers, reliability initiatives, fuel and purchased power (which account for a substantial portion of our operating costs), customer switching, capital expenditures and investments and other costs on a full or timely basis through rates, power market prices, and changes to the frequency and timing of rate increases could have a material adverse effect on our results of operations, financial condition and cash flows.

Our increased costs due to advanced energy and energy efficiency requirements may not be fully recoverable in the future.

SB 221 contained targets relating to advanced energy, renewable energy, peak demand reduction and energy efficiency standards. SB 310 was passed in 2014 that modified the energy efficiency and renewable targets. It eliminated the advanced energy targets and the in state requirement for renewable energy. Annual targets for energy efficiency began in 2009 and require increasing energy reductions each year compared to a baseline energy usage, up to 22.3% by 2025.  Peak demand reduction targets began in 2009 with increases in required percentages each year, up to 7.75% by 2018. The renewable energy standards have increased our power supply costs and are expected to continue to increase (and could materially increase) these costs. DP&L is entitled to recover costs associated with its alternative energy compliance costs, as well as its energy efficiency and demand response programs. DP&L began recovering these costs in 2009. If in the future we are unable to timely or fully recover these costs, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, if we were found not to be in compliance with these standards, monetary penalties could apply. These penalties are not permitted to be recovered from customers and significant penalties could have a material adverse effect on our results of operations, financial condition and cash flows. The demand reduction and energy efficiency standards by design result in reduced energy and demand that could adversely affect our results of operations, financial condition and cash flows.

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The availability and cost of fuel has experienced and could continue to experience significant volatility and we may not be able to hedge the entire exposure of our operations from fuel availability and price volatility.

We purchase coal, natural gas and other fuel from a number of suppliers. The coal market in particular has experienced significant price volatility in the last several years. We are now in a global market for coal in which our domestic price is increasingly affected by international supply disruptions and demand balance. Coal exports from the U.S. have increased significantly at times in recent years. In addition, domestic issues like government-imposed direct costs and permitting issues that affect mining costs and supply availability, and the variable demand of retail customer load and the performance of our generation fleet have an impact on our fuel procurement operations. Our approach is to hedge the fuel costs for our anticipated electric sales. However, we may not be able to hedge the entire exposure of our operations from fuel price volatility. As of the date of this prospectus, DP&L has substantially all of the expected coal volume needed under contract to meet its retail and wholesale sales requirements for 2015. Historically, some of our suppliers and buyers of fuel have not performed on their contracts and have failed to deliver or accept fuel as specified under their contracts. To the extent our suppliers and buyers do not meet their contractual commitments and, as a result of such failure or otherwise, we cannot secure adequate fuel or sell excess fuel in a timely or cost-effective manner or we are not hedged against price volatility, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, DP&L is a co-owner of certain generation facilities where it is a non-operating owner. DP&L does not procure or have control over the fuel for these facilities, but is responsible for its proportionate share of the cost of fuel procured at these facilities. Co-owner operated facilities do not always have realized fuel costs that are equal to our co-owners projections, and we are responsible for our proportionate share of any increase in actual fuel costs. Fuel and purchased power costs represent a large and volatile portion of DP&L’s total cost. DP&L implemented a fuel and purchased power recovery mechanism beginning on January 1, 2010, which subjects our recovery of fuel and purchased power costs to tracking and adjustment on a seasonal quarterly basis for SSO customers but will be totally phased out by January 1, 2016. If in the future we are unable to timely or fully recover our fuel and purchased power costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.

Fluctuations in our sales of coal and excess emission allowances could cause a material adverse effect on our results of operations, financial condition and cash flows for any particular period.

DP&L sells coal to other parties from time to time for reasons that include maintaining an appropriate balance between projected supply and projected use and as part of a coal price optimization program where coal under contract may be resold and replaced with other coal or power available in the market with a favorable price spread, adjusted for any quality differentials. Sales of coal are affected by a range of factors, including price volatility among the different coal basins and qualities of coal, variations in power demand and the market price of power compared to the cost to produce power. These factors could cause the amount and price of coal we sell to fluctuate, which could have a material adverse effect on our results of operations, financial condition and cash flows for any particular period.

DP&L may sell its excess emission allowances, including NO_x and SO₂ emission allowances, from time to time. Sales of any excess emission allowances are affected by a range of factors, such as general economic conditions, fluctuations in market demand, availability of excess inventory for sale and changes to the regulatory environment, including the implementation of CSAPR. These factors could cause the amount and price of excess emission allowances DP&L sells to fluctuate, which could have a material adverse effect on DPL’s results of operations, financial condition and cash flows for any particular period. Although there has been overall reduced trading activity in the annual NO_x and SO₂  emission allowance trading markets in recent years, the adoption of regulations that regulate emissions or establish or modify emission allowance trading programs could affect the emission allowance trading markets and have a material effect on DP&L’s emission allowance sales.

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If legislation or regulations at the federal, state or regional levels impose mandatory reductions of greenhouse gases on generation facilities, we could be required to make large additional capital investments and incur substantial costs.

There is an ongoing concern nationally and internationally among regulators, investors and others concerning global climate change and the contribution of emissions of GHGs, including most significantly CO₂. This concern has led to interest in legislation and action at the international, federal, state and regional levels, including regulation of GHG emissions by the USEPA, and litigation seeking to compel the promulgation or enforcement of GHG requirements. Approximately 99% of the energy we produce is generated by coal. As a result of current or future legislation or regulations at the international, federal, state or regional levels imposing mandatory reductions of CO₂ and other GHGs on generation facilities, we could be required to make large additional capital investments and/or incur substantial costs in the form of taxes or emissions allowances. Such legislation and regulations could also impair the value of our generation stations or make some of these stations uneconomical to maintain or operate and could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing generation stations. Although DP&L is permitted under its current ESP to seek recovery of costs associated with new climate change or GHG regulations, our inability to fully or timely recover such costs could have a material adverse effect on our results of operations, financial condition and cash flows.

We are subject to numerous environmental laws and regulations that require capital expenditures, increase our cost of operations, may expose us to environmental liabilities or make continued operation of certain generating units unprofitable.

Our operations and facilities (both wholly-owned and co-owned with others) are subject to numerous and extensive federal, state and local environmental laws and regulations relating to various matters, including air quality (such as reductions in NO_x, SO₂ and particulate emissions), water quality, wastewater discharge, solid waste and hazardous waste. We could also become subject to additional environmental laws and regulations and other requirements in the future (such as reductions in mercury and other hazardous air pollutants, SO₃ (sulfur trioxide), regulation of ash generated from coal-based generating stations and reductions in GHG emissions as discussed in more detail in the next risk factor). With respect to our largest generation station, the Stuart generating station, we are also subject to continuing compliance requirements related to NO_x, SO₂ and particulate matter emissions under DP&L’s consent decree with the Sierra Club. Compliance with these laws, regulations and other requirements requires us to expend significant funds and resources and could at some point become prohibitively expensive or result in our shutting down (temporarily or permanently) or altering the operation of our facilities. Environmental laws and regulations also generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. If we are not able to timely obtain, maintain or comply with all licenses, permits, inspections and approvals required to operate our business, then our operations could be prevented, delayed or subject to additional costs. Failure to comply with environmental laws, regulations and other requirements may result in the imposition of fines and penalties or other sanctions and the imposition of stricter environmental standards and controls and other injunctive measures affecting operating assets. In addition, any alleged violation of these laws, regulations and other requirements may require us to expend significant resources to defend against any such alleged violations. DP&L owns a non-controlling interest in several generating stations operated by our co-owners. As a non-controlling owner in these generating stations, DP&L is responsible for its pro rata share of expenditures for complying with environmental laws, regulations and other requirements, but has limited control over the compliance measures taken by our co-owners. DP&L’s ESP permits it to seek recovery for costs associated with new climate change or carbon regulations. In addition, if we were found not to be in compliance with these environmental laws, regulations or requirements, any penalties that would apply or other resulting costs would likely not be recoverable from customers. We could be subject to joint and several strict liabilities for any environmental contamination at our currently or formerly owned, leased or operated properties or third-party waste disposal sites. For example, contamination has been identified at two waste disposal sites for which we are alleged to have potential liability. In addition to potentially significant investigation and remediation costs, any such contamination matters can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage.

Our costs and liabilities relating to environmental matters could have a material adverse effect on our results of operations, financial condition and cash flows.

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Our use of derivative and nonderivative contracts may not fully hedge our generation assets, customer supply activities, or other market positions against changes in commodity prices, and our hedging procedures may not work as planned.

We transact in coal, power and other commodities to hedge our positions in these commodities. These trades are affected by a range of factors, including variations in power demand, fluctuations in market prices, market prices for alternative commodities and optimization opportunities. We have attempted to manage our commodities price risk exposure by establishing and enforcing risk limits and risk management policies. Despite our efforts, however, these risk limits and management policies may not work as planned and fluctuating prices and other events could adversely affect our results of operations, financial condition and cash flows. As part of our risk management, from time to time, we use a variety of non-derivative and derivative instruments, such as swaps, futures and forwards, to manage our market risks. We also use, from time to time, interest rate derivative instruments to hedge against interest rate fluctuations related to our debt. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. We could also recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform, which could result in a material adverse effect on our results of operations, financial condition and cash flows.

The Dodd-Frank Act contains significant requirements related to derivatives that, among other things, could reduce the cost effectiveness of entering into derivative transactions.

In July 2010, The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was signed into law. The Dodd-Frank Act contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. We are considered an end-user under the Dodd-Frank Act and therefore are exempt from most of the collateral and margining requirements. We are required to report our bilateral derivative contracts, unless our counterparty is a major swap participant or has elected to report on our behalf.  Even though we qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits or be unable to enter into certain transactions with us. The occurrence of any of these events could have an adverse effect on our results of operations, financial condition and cash flows.

Our financial results may fluctuate on a seasonal and quarterly basis or as a result of severe weather.

Weather conditions significantly affect the demand for electric power. In our Ohio service territory, demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating compared to other times of the year. Unusually mild summers and winters could therefore have an adverse effect on our results of operations, financial condition and cash flows. In addition, severe or unusual weather, such as hurricanes and ice or snow storms, may cause outages and property damage that may require us to incur additional costs that may not be insured or recoverable from customers. While DP&L is permitted to seek recovery of storm damage costs, if DP&L is unable to fully recover such costs in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.

Costs associated with new transmission projects could have a material adverse effect on our results of operations, financial condition and cash flows.

Annually, PJM performs a review of the capital additions required to provide reliable electric transmission services throughout its territory. PJM traditionally allocated the costs of constructing these facilities to those entities that benefited directly from the additions. Over the last several years, however, some of the costs of constructing new large transmission facilities have been socialized across PJM without a direct relationship between the costs assigned to and benefits received by particular PJM members. To date, the additional costs charged to DP&L for new large transmission approved projects have not been material. Over time, as more new transmission projects are constructed and if the allocation method is not changed, the annual costs could become material. DP&L is recovering the Ohio retail jurisdictional share of these allocated costs from its retail customers through the TCRR-N rider. To the extent that any costs in the future are material and we are unable

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to recover them from our customers, it could have a material adverse effect on our results of operation, financial condition and cash flows.

We have no control over the timing or terms of an order by the PUCO ordering us to separate our generation business into a separate legal entity from our distribution and transmission business.

As required by the 2014 ESP order, DP&L filed an application for authority to transfer or sell its generation assets no later than January 1, 2017. There can be no assurance of the terms on which the PUCO would authorize the separation of our generation business from our distribution and transmission business. Although the initial PUCO order approved our separation plan, several regulatory filings and approvals are required in connection with the separation and certain other consents or approvals may be required under other agreements to which we are party.

If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties. These would likely not be recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.

As an owner and operator of a bulk power transmission system, DP&L is subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. In addition, DP&L is subject to Ohio reliability standards and targets. Compliance with reliability standards subjects us to higher operating costs or increased capital expenditures. While we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the PUCO will approve full recovery in a timely manner. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.

Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows.

From time to time we rely on access to the credit and capital markets to fund certain operational and capital costs. These capital and credit markets have experienced extreme volatility and disruption and the ability of corporations to obtain funds through the issuance of debt or equity has been negatively impacted. Disruptions in the credit and capital markets make it harder and more expensive to obtain funding for our business. Access to funds under our existing financing arrangements is also dependent on the ability of our counterparties to meet their financing commitments. Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows. If our available funding is limited or we are forced to fund our operations at a higher cost, these conditions may require us to curtail our business activities and increase our cost of funding, both of which could reduce our profitability. DP&L has variable rate debt that bears interest based on a prevailing rate that is reset weekly based on a market index that can be affected by market demand, supply, market interest rates and other market conditions. We also maintain both cash on deposit and investments in cash equivalents, from time to time, that could be adversely affected by interest rate fluctuations. In addition, ratings agencies issue credit ratings on us and our debt that affect our borrowing costs under our financial arrangements and affect our potential pool of investors and funding sources. Our credit ratings also govern the collateral provisions of certain of our contracts. As a result of the Merger and assumption by DPL of merger-related debt and other factors, our credit ratings were downgraded, resulting in increased borrowing costs and causing us to post cash collateral with certain of our counterparties. If the rating agencies were to downgrade our credit ratings further, our borrowing costs would likely further increase, our potential pool of investors and funding resources could be reduced, and we could be required to post additional cash collateral under selected contracts. These events would likely reduce our liquidity and profitability and could have a material adverse effect on our results of operations, financial condition and cash flows.

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Our membership in a regional transmission organization presents risks that could have a material adverse effect on our results of operations, financial condition and cash flows.

On October 1, 2004, in compliance with Ohio law, DP&L turned over control of its transmission functions and fully integrated into PJM, a regional transmission organization.  The price at which we can sell our generation capacity and energy is now dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion and PJM s business rules.  While we can continue to make bilateral transactions to sell our generation through a willing-buyer and willing-seller relationship, any transactions that are not pre-arranged are subject to market conditions at PJM.  To the extent we sell electricity into the power markets on a contractual basis, we are not guaranteed any rate of return on our capital investments through mandated rates. The results of the PJM RPM base residual auction are impacted by the supply and demand of generation and load and also may be impacted by congestion and PJM rules relating to bidding for Demand Response and Energy Efficiency resources and other factors. Auction prices could fluctuate substantially over relatively short periods of time and adversely affect our results of operations, financial condition and cash flows. We cannot predict the outcome of future auctions, but low auction prices could have a material adverse effect on our results of operations, financial condition and cash flows.

The rules governing the various regional power markets may also change from time to time which could affect our costs and revenues and have a material adverse effect on our results of operations, financial condition and cash flows. We may be required to expand our transmission system according to decisions made by PJM rather than our internal planning process. Various proposals and proceedings before FERC may cause transmission rates to change from time to time.  In addition, PJM has been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial effect on us.  We also incur fees and costs to participate in PJM.

SB 221 includes a provision that allows electric utilities to seek and obtain recovery of RTO-related charges. Therefore, non-market based costs are being recovered from all retail customers through the TCRR-N, and market based RTO-related costs associated with serving SSO load are being recovered from SSO customers through our TCRR-B. If in the future, however, we are unable to recover all of these costs in a timely manner, and since the TCRR-B rider is bypassable when additional customer switching occurs, this could have a material adverse effect on our results of operations, financial condition and cash flows.

As members of PJM, DP&L and DPLE are also subject to certain additional risks including those associated with the allocation of losses caused by unreimbursed defaults of other participants in PJM markets among PJM members and those associated with complaint cases filed against PJM that may seek refunds of revenues previously earned by PJM members including DP&L and DPLE. These amounts could be significant and have a material adverse effect on our results of operations, financial condition and cash flows.

If the pending PJM Capacity Performance proposal(s) before the FERC affecting capacity pricing and penalties for lack of performance by generators are approved as filed, we could be subject to substantial changes in capacity income and/or penalties.

As the owner of generation that is a capacity resource within PJM, DP&L is subject to mandatory requirements to participate in PJM markets. The existing PJM capacity market is in the process of being restructured and the existing RPM capacity market requirements are likely to be replaced by a Capacity Performance program that offers the potential for higher capacity prices but paired with higher penalties for non-performance during times of high electricity demand. Any such penalties incurred are likely not recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.

Our consolidated results of operations may be negatively affected by overall market, economic and other conditions that are beyond our control.

Economic pressures, as well as changing market conditions and other factors related to physical energy and financial trading activities, which include price, credit, liquidity, volatility, capacity, transmission and interest rates, can have a significant effect on our operations and the operations of our retail, industrial and commercial

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customers and our suppliers. The direction and relative strength of the economy has been increasingly uncertain due to softness in the real estate and mortgage markets, volatility in fuel and other energy costs, difficulties in the financial services sector and credit markets, high unemployment and other factors. Many of these factors have affected our Ohio service territory.

Overall lower prices in the retail electricity market have led to increased switching from DP&L to other CRES providers, including DPLER, who may be offering retail prices lower than DP&L’s SSO price. Also, several municipalities in DP&L’s service territory have passed ordinances allowing them to become government aggregators and some municipalities have contracted with CRES providers to provide generation service to the customers located within the municipal boundaries, further contributing to the switching trend. CRES providers have also become more active in DP&L’s service territory. These factors may reduce our margins and could have a material adverse effect on our results of operations, financial condition and cash flows.

Our results of operations, financial condition and cash flows may be negatively affected by sustained downturns or a sluggish economy. Sustained downturns, recessions or a sluggish economy generally affect the markets in which we operate and negatively influence our energy operations. A contracting, slow or sluggish economy could reduce the demand for energy in areas in which we are doing business. During economic downturns, our commercial and industrial customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of energy they require. In addition, our customers’ ability to pay us could also be impaired, which could result in an increase in receivables and write-offs of uncollectible accounts. Our suppliers could also be affected by the economic downturn resulting in supply delays or unavailability. Reduced demand for our electric services, failure by our customers to timely remit full payment owed to us and supply delays or unavailability could have a material adverse effect on our results of operations, financial condition and cash flows.

A material change in market interest rates could adversely affect our results of operations, financial condition and cash flows.

DPL and DP&L have variable rate debt that bears interest based on a prevailing rate that is regularly reset and that can be affected by market demand, supply, market interest rates and other market conditions. We also, from time to time, maintain both cash on deposit and investments in cash equivalents that could be adversely affected by interest rate fluctuations. Any event which impacts market interest rates could have a material adverse effect on our results of operations, financial condition and cash flows.

Poor investment performance of our benefit plan assets and other factors impacting benefit plan costs could unfavorably affect our liquidity and results of operations.

The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under our pension and postemployment benefit plans. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the pension and postemployment benefit plan assets will increase the funding requirements under our pension and postemployment benefit plans if the actual asset returns do not recover these declines in value in the foreseeable future. Future pension funding requirements, and the timing of funding payments, may also be subject to changes in legislation. The Pension Protection Act, enacted in August 2006, requires underfunded pension plans to improve their funding ratios within prescribed intervals based on the level of their underfunding. As a result, our required contributions to these plans, at times, have increased and may increase in the future. In addition, our pension and postemployment benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the discounted liabilities increase benefit expense and funding requirements. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements for the obligations related to the pension and other postemployment benefit plans. Declines in market values and increased funding requirements could have a material adverse effect on our results of operations, financial condition and cash flows.

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Our businesses depend on counterparties performing in accordance with their agreements. If they fail to perform, we could incur substantial expense, which could adversely affect our liquidity, cash flows and results of operations.

We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, including fuel and equipment components (such as limestone for our FGD equipment), for our capital improvements and additions and to provide professional services, such as actuarial calculations, payroll processing and various consulting services. If any of these counterparties fails to perform its obligations to us or becomes unavailable, our business plans may be materially disrupted, we may be forced to discontinue certain operations if a cost-effective alternative is not readily available or we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause delays. These events could cause our results of operations, financial condition and cash flows to have a material adverse effect.

Accidental improprieties and undetected errors in our internal controls and information reporting could result in the disallowance of cost recovery, noncompliant disclosure and reporting or incorrect payment processing.

Our internal controls, accounting policies and practices and internal information systems are designed to enable us to capture and process transactions and information in a timely and accurate manner in compliance with GAAP in the United States of America, laws and regulations, taxation requirements and federal securities laws and regulations in order to, among other things, disclose and report financial and other information in connection with the recovery of our costs and with our reporting requirements under federal securities, tax and other laws and regulations and to properly process payments. We have also implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002. Our internal controls and policies have been and continue to be closely monitored by management and our Board of Directors. While we believe these controls, policies, practices and systems are adequate to verify data integrity, unanticipated and unauthorized actions of employees, temporary lapses in internal controls due to shortfalls in oversight or resource constraints could lead to improprieties and undetected errors that could result in the disallowance of cost recovery, noncompliant disclosure and reporting or incorrect payment processing. The consequences of these events could have a material adverse effect on our results of operations, financial condition and cash flows.

New accounting standards or changes to existing accounting standards could materially affect how we report our results of operations, financial condition and cash flows.

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially affect how we report our results of operations, financial condition and cash flows. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial condition. In addition, in preparing our consolidated financial statements, management is required to make estimates and assumptions. Actual results could differ significantly from those estimates.

The SEC is investigating the potential transition to the use of IFRS promulgated by the International Accounting Standards Board for U.S. companies. Adoption of IFRS could result in significant changes to our accounting and reporting, such as in the treatment of regulatory assets and liabilities and property. The SEC does not currently have a timeline regarding the mandatory adoption of IFRS. We are currently assessing the effect that this potential change would have on our consolidated financial statements and we will continue to monitor the development of the potential implementation of IFRS.

We are subject to extensive laws and local, state and federal regulation, as well as related litigation that could affect our operations and costs.

We are subject to extensive laws and regulation by federal, state and local authorities, such as the PUCO, the CFTC, the USEPA, the Ohio EPA, the FERC, the Department of Labor and the Internal Revenue Service, among others. Regulations affect almost every aspect of our business, including in the areas of the environment,

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health and safety, cost recovery and rate making, the issuance of securities and incurrence of debt and taxation. New laws and regulations, and new interpretations of existing laws and regulations, are ongoing and we generally cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on our business. Complying with this regulatory environment requires us to expend a significant amount of funds and resources. The failure to comply with this regulatory environment could subject us to substantial financial costs and penalties and changes, either forced or voluntary, in the way we operate our business. Additional detail about the effect of this regulatory environment on our operations is included in the risk factors set forth below. In the normal course of business, we are also subject to various lawsuits, actions, proceedings, claims and other matters asserted under this regulatory environment or otherwise, which require us to expend significant funds to address, the outcomes of which are uncertain and the adverse resolutions of which could have a material adverse effect on our results of operations, financial condition and cash flows.

If we are unable to maintain a qualified and properly motivated workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows.

One of the challenges we face is to retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to resignations, terminations or retirements. This undertaking could require us to make additional financial commitments and incur increased costs. If we are unable to successfully attract and retain an appropriately qualified workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we have employee compensation plans that reward the performance of our employees. We seek to ensure that our compensation plans encourage acceptable levels for risk and high performance through pay mix, performance metrics and timing. We also have policies and procedures in place to mitigate excessive risk-taking by employees since excessive risk-taking by our employees to achieve performance targets could result in events that could have a material adverse effect on our results of operations, financial condition and cash flows.

We are subject to collective bargaining agreements and other employee workforce factors that could affect our businesses.

Over half of our employees are represented by a collective bargaining agreement that is in effect until October 31, 2017. While we believe that we maintain a satisfactory relationship with our employees, it is possible that labor disruptions affecting some or all of our operations could occur during the period of the collective bargaining agreement or at the expiration of the collective bargaining agreement before a new agreement is negotiated. Work stoppages by, or poor relations or ineffective negotiations with, our employees could have a material adverse effect on our results of operations, financial condition and cash flows.

Potential security breaches (including cybersecurity breaches) and terrorism risks could adversely affect our businesses.

We operate in a highly regulated industry that requires the continued operation of sophisticated systems and network infrastructure at our generation stations, fuel storage facilities and transmission and distribution facilities. We also use various financial, accounting and other systems in our businesses. These systems and facilities are vulnerable to unauthorized access due to hacking, viruses, other cybersecurity attacks and other causes. In particular, given the importance of energy and the electric grid, there is the possibility that our systems and facilities could be targets of terrorism or acts of war.  We have implemented measures to help prevent unauthorized access to our systems and facilities, including certain measures to comply with mandatory regulatory reliability standards. Despite our efforts, if our systems or facilities were to be breached or disabled, we may be unable to recover them in a timely way to fulfill critical business functions, including the supply of electric services to our customers, and we could experience decreases in revenues and increases in costs that could adversely affect our results of operations, cash flows and financial condition.

In the course of our business, we also store and use customer, employee, and other personal information and other confidential and sensitive information. If our third party vendors systems were to be breached or disabled, sensitive and confidential information and other data could be compromised, which could result in negative publicity, remediation costs and potential litigation, damages, consent orders, injunctions, fines and other relief.

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To help mitigate against these risks, we maintain insurance coverage against some, but not all, potential losses, including coverage for illegal acts against us. However, insurance may not be adequate to protect us against all costs and liabilities associated with these risks.

Impairment of goodwill or long-lived assets would negatively affect our consolidated results of operations and net worth.

Goodwill represents the future economic benefits arising from assets acquired in a business combination (acquisition) that are not individually identified and separately recognized. Goodwill is not amortized, but is evaluated for impairment 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. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions, operating or regulatory environment; increased competitive environment; increase in fuel costs particularly when we are unable to pass along such costs to customers; negative or declining cash flows; loss of a key contract or customer, particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods. See Note 5 of notes to our consolidated financial statements for more information on the impairment of Goodwill.

Long-lived assets are initially recorded at fair value when acquired in a business combination and are amortized or depreciated over their estimated useful lives. Long-lived assets are evaluated for impairment only when impairment indicators are present whereas goodwill is evaluated for impairment on an annual basis or more frequently if potential impairment indicators are present. Otherwise, the recoverability assessment of long-lived assets is similar to the potential impairment evaluation of goodwill particularly as it relates to the identification of potential impairment indicators, and making estimates and assumptions to determine fair value, as described above. See Note 15 of notes to our consolidated financial statements for more information on the impairment of fixed assets.

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Cautionary Note Regarding Forward-Looking Statements

This prospectus includes certain “forward-looking statements” that involve many risks and uncertainties.  Forward-looking statements express an expectation or belief and contain a projection, plan or assumption with regard to, among other things, our future revenues, income, expenses or capital structure. Such statements of future events or performance are not guarantees of future performance and involve estimates, assumptions and uncertainties. The words “could,” “may,” “predict,” “anticipate,” “would,” “believe,” “estimate,” “expect,” “forecast,” “project,” “objective,” “intend,” “continue,” “should,” “plan,” and similar expressions, or the negatives thereof, are intended to identify forward-looking statements unless the context requires otherwise.  These forward-looking statements are based on management’s present expectations and beliefs about future events. As with any projection or forecast, these statements are inherently susceptible to uncertainty and changes in circumstances. We are under no obligation to, and expressly disclaim any obligation to, update or alter the forward-looking statements whether as a result of such changes, new information, subsequent events or otherwise. If we do update one or more forward-looking statements, no inference should be made that we will make additional updates with respect to those or other forward-looking statements.

Important factors that could cause actual results to differ materially from those reflected in such forward-looking statements and that should be considered in evaluating our outlook include, but are not limited to, the following:

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

· unusual maintenance or repair requirements;

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

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

· performance of our suppliers;

· increased competition and deregulation in the electric utility industry;

· increased competition in the retail generation market;

· availability and price of capacity;

· changes in interest rates;

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

· changes in environmental laws and regulations to which we and our subsidiaries are subject;

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

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

· significant delays associated with large construction projects;

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

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

· financial market conditions;

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

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

· general economic conditions; and

· the risks and other factors discussed elsewhere in this prospectus

All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and many are beyond our control. See “Risk Factors” for a more detailed discussion of the foregoing and certain other factors that could cause actual results to differ materially from those reflected in such forward-looking statements and that should be considered in evaluating our outlook.

Use of Proceeds

We will not receive any cash proceeds from the issuance of the new notes.  The new notes will be exchanged for old notes as described in this prospectus upon our receipt of old notes. We will cancel all of the old notes surrendered in exchange for the new notes.

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Ratio of Earnings to Fixed Charges

The following table presents our ratio of earnings to fixed charges for the periods indicated:

	Three months ended March 31,		Year Ended December 31,
	2015		2014		2013		2012		2011		2010
Ratio of earnings to fixed charges		2.34		NM*		NM*		NM*		4.37		6.95

* Not a meaningful ratio due to goodwill and fixed asset impairments recorded during the three months ended March 31, 2014 and the years ended December 31, 2014, 2013 and 2012. As such, the earnings are inadequate to cover fixed charges, and the coverage deficiency is $57.9 million, $201.6 million and $1,684.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.

The Ratio of Earnings to Fixed Charges represents, on a pre-tax basis, the number of times earnings cover fixed charges. Earnings consist of earnings before income tax expense and fixed charges. Fixed charges consist of interest on long term-debt, other interest expense, dividends on the preferred stock of subsidiaries and an estimate of the interest portion of all rentals charged to income. Dividends on the preferred stock of subsidiaries are not included in the fixed charges that are added back to earnings.

The following table represents our ratio of earnings to fixed charges (as adjusted) for the periods indicated:

	Three months ended March 31,		Year Ended December 31,
	2015		2014		2013		2012		2011		2010
Adjusted Ratio of earnings to fixed charges		2.34		1.70		2.04		2.06		4.37		6.95

The Adjusted Ratio of Earnings to Fixed Charges represents, on a pre-tax basis, the number of times adjusted earnings cover fixed charges. Adjusted earnings consist of earnings before income tax expense and fixed charges as well as goodwill and fixed asset impairments recorded during the years ended December 31, 2014, 2013 and 2012. Fixed charges consist of interest on long-term debt, other interest expense, dividends on the preferred stock of subsidiaries and an estimate of the interest portion of all rentals charged to income. Dividends on the preferred stock of subsidiaries are not included in the fixed charges that are added back to earnings. Goodwill and fixed-asset impairments recorded during the years ended December 31, 2014, 2013 and 2012 are excluded from the Adjusted Ratio of Earnings to Fixed Charges as these non-cash charges would not affect the Company’s ability to cover its fixed charges in the future.

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Capitalization

The following table sets forth a summary of our consolidated capitalization as of March 31, 2015:

This table should be read in conjunction with “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and the consolidated financial statements and related notes included herein.

	As of March 31, 2015
	(in millions)
Current portion of long-term debt	$	30.1
Long-term debt:
1.875% first mortgage bonds due 2016		445.0
4.70% pollution control bonds due 2028		35.3
4.80% pollution control bonds due 2034		179.1
4.80% pollution control bonds due 2036		100.0
Variable rate pollution control bonds due 2040		100.0
U.S. Government note due 2061		18.1
8.125% note to DPL Capital Trust II due 2031		15.6
6.50% senior notes due 2016		130.0
6.75% senior notes due 2019		200.0
7.25% senior notes due 2021		780.0
Unsecured term loan facility		130.0
Unamortized debt discounts		(3.5	)
Total long-term debt		2,129.6
Redeemable preferred stock of subsidiary		18.4
Common shareholders’ equity:
1,500 shares authorized; 1 share issued and outstanding at December 31, 2014	$	—
Other paid-in capital		2,237.5
Accumulated other comprehensive income		8.4
Retained earnings / (deficit)		(2,068.0	)
Total common shareholders’ equity		177.9
Total capitalization	$	2,356.0

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Selected Consolidated Financial and Other Data

The table below presents our selected historical consolidated financial and other data for the periods presented, which should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included herein.

The selected historical consolidated statement of operations data and balance sheet data for each of the years ended December 31, 2014, 2013 and 2012 are derived from our audited consolidated financial statements included herein. The selected historical statement of operations data and balance sheet data for each of the years ended December 31, 2011 and 2010 are derived from our audited consolidated financial statements not included herein. The selected historical consolidated statement of operations data and balance sheet data for each of the three months ended March 31, 2015 and 2014 are derived from our unaudited condensed consolidated financial statements included herein. The unaudited condensed consolidated financial statements have been prepared on the same basis as the audited consolidated financial statements and, in the opinion of management, include all adjustments, consisting only of normal recurring adjustments, necessary to present fairly the data for the period. Our historical results for any prior period are not necessarily indicative of results to be expected for any future period.

	DPL
	Successor(1)																	Predecessor(1)
	Three months ended March 31, 2015		Three months ended March 31, 2014			Year ended December 31, 2014			Year ended December 31, 2013			Year ended December 31, 2012			November 28, 2011 through December 31, 2011			January 1, 2011 through November 27, 2011		Year ended December 31, 2010
	$ in millions except as indicated
Statement of operations data:
Revenues	$	494.5	$	460.3		$	1,763.0		$	1,636.9		$	1,668.4		$	156.9		$	1,670.9	$	1,831.4
Goodwill impairment(3)	$	—	$	(135.8	)	$	(135.8	)	$	(306.3	)	$	(1,817.2	)	$	—		$	—	$	—
Fixed-asset impairment(5)	$	—	$	(11.5	)	$	(11.5	)	$	(26.2	)	$	—		$	—		$	—	$	—
Net income /(loss)(2)	$	28.7	$	(249.0	)	$	(74.6	)	$	(222.0	)	$	(1,729.8	)	$	(6.2	)	$	150.5	$	290.3
Other operating data
Total electric sales (millions of kWh)		5,082		5,375			18,763			19,561			16,454			1,361			15,021		17,237
Balance sheet data (end of period):
Total assets	$	3,553.9	$	3,591.3		$	3,577.8		$	3,721.5		$	4,247.3		$	6,136.2			N/A	$	3,813.3
Long-term debt(4)	$	2,129.6	$	2,274.2		$	2,139.6		$	2,284.2		$	2,025.0		$	2,628.9			N/A	$	1,026.6
Total construction additions	$	133.4	$	135.9		$	115.6		$	114.4		$	179.6		$	201.0			N/A	$	151.4
Redeemable preferred stock of subsidiary	$	18.4	$	18.4		$	18.4		$	18.4		$	18.4		$	18.4			N/A	$	22.9

(1) Predecessor refers to the operations of DPL and its subsidiaries prior to the Merger date. Successor refers to the operations of DPL and its subsidiaries subsequent to the Merger date.

(2) DPL incurred merger-related costs of $37.9 million ($24.6 million net of tax) and $15.7 million ($10.2 million net of tax) in the 2011 Predecessor and Successor periods, respectively, and had a $25.1 million ($16.3 million net of tax) favorable adjustment in the period January 1, 2011 through November 27, 2011 as a result of the approval of the fuel settlement agreement by the PUCO.

(3) Goodwill impairments of $135.8 million, $306.3 million and $1,817.2 million were recorded in 2014, 2013 and 2012, respectively and $0.0 million and $135.8 million for the three months ended March 31, 2015 and 2014, respectively.

(4) Excludes current maturities of long-term debt.

(5) For DPL, fixed-asset impairments of $11.5 million ($7.5 million net of tax) and $26.2 million ($17.0 million net of tax) were recorded in 2014 and 2013, respectively and $0.0 million and $11.5 million ($7.5 million net of tax) for the three months ended March 31, 2015 and 2014, respectively.

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Management’s Discussion and Analysis of Results of
Operations and Financial Condition

The following discussion and analysis should be read in conjunction with the financial statements and notes thereto included elsewhere in this prospectus. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. Please see “Cautionary Note Regarding Forward Looking Statements” and “Risk Factors” in this prospectus.

Business Overview

DPL is a regional electric energy and utility company. DPL’s two reporting segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary and, until April 1, 2015, DPLER’s subsidiary, MC Squared, which was recently sold in a stock purchase transaction. See “Summary—Recent Developments.” See Note 14 of notes to DPL’s consolidated financial statements for more information relating to these reportable segments.

DP&L is primarily engaged in the generation, transmission and distribution of electricity in West Central Ohio and the sale of energy to DPLER in Ohio. DPL and DP&L strive to achieve disciplined growth in energy margins while limiting volatility in both cash flows and earnings and to achieve stable, long-term growth through efficient operations and strong customer and regulatory relations. More specifically, DPL’s and DP&L’s strategy is to match energy supply with load or customer demand, maximizing profits while effectively managing exposure to movements in energy and fuel prices and utilizing the transmission and distribution assets that transfer electricity at the most efficient cost while maintaining the highest level of customer service and reliability.

We operate and manage generation assets and are exposed to a number of risks. These risks include, but are not limited to, electricity wholesale price risk, PJM capacity price risk, regulatory risk, environmental risk, fuel supply and price risk, customer switching risk and the risk associated with electric generating station performance. We attempt to manage these risks through various means. For instance, we operate a portfolio of wholly-owned and jointly-owned generation assets that is diversified as to coal source, cost structure and operating characteristics. We are focused on the operating efficiency of these stations and maintaining their availability.

We operate and manage transmission and distribution assets in a rate-regulated environment. Accordingly, this subjects us to regulatory risk in terms of the costs that we may recover and the investment returns that we may collect in customer rates. We are focused on delivering electricity and maintaining high standards of customer service and reliability in a cost-effective manner.

Additional information relating to our risks is contained in “Risk Factors” elsewhere in this prospectus.

The following discussion should be read in conjunction with the accompanying consolidated financial statements and related notes included elsewhere in this prospectus.

Business Combination

Acquisition by The AES Corporation

On November 28, 2011, DPL merged with Dolphin Sub, Inc., a wholly-owned subsidiary of AES pursuant to the Merger agreement whereby AES acquired DPL for $30.00 per share in a cash transaction valued at approximately $3.5 billion. At closing, DPL became a wholly-owned subsidiary of AES.

Dolphin Subsidiary II, Inc., a subsidiary of AES, issued $1.25 billion in long-term Senior Notes on October 3, 2011, to partially finance the Merger. Upon the consummation of the Merger, Dolphin Subsidiary II, Inc. was merged into DPL and these notes became long-term debt obligations of DPL. This debt has had and will continue to have a material effect on DPL’s cash requirements.

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Regulatory Environment

DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated.

Carbon Dioxide and Other Greenhouse Gas Emissions

There is on-going concern nationally and internationally about global climate change and the contribution of emissions of GHGs, including most significantly CO₂. This concern has led to regulation and interest in legislation at the federal level, actions at the state level as well as litigation relating to GHG emissions. The USEPA began regulating GHG emissions from certain stationary sources in January 2011, under regulations referred to as the Tailoring Rule. In June 2014, the U.S. Supreme Court ruled that the USEPA had exceeded its statutory authority in issuing the so-called Tailoring Rule under Section 165 of the CAA by regulating sources under the PSD program based solely on their GHG emissions, but also held that the USEPA could impose GHG BACT requirements for sources already required to implement PSD for certain other pollutants.

In January 2014, the USEPA proposed revised GHG New Source Performance Standards for new EGUs under CAA subsection 111(b), which would require new EGUs to limit the amount of CO₂ emitted per megawatt-hour. The proposal anticipates that affected coal-fired units would need to rely upon partial implementation of carbon capture and storage or other expensive CO₂ emission control technology to meet the standard. In addition, new natural gas-fired EGUs must meet a standard of no greater than 1,000 pounds of CO₂ per megawatt hour (if the rule is finalized in its current form). The rule is expected to be finalized in mid-2015.

The USEPA issued proposed rules establishing GHG performance standards for existing power plants under CAA Section 111(d) on June 2, 2014.  Under the proposed rule, states would be judged against state-specific carbon dioxide emissions targets beginning in 2020, with expected total U.S. power section emissions reduction of 30% from 2005 levels by 2030. The proposed rule requires states to SIPs to meet the standards set forth in the rule by June 30, 2016, with the possibility of one or two-year extensions under certain circumstances.  The proposed rule was subject to a public comment process and the USEPA is expected to finalize it by July 2015.  Among other things, the Company could be required to make efficiency improvements to existing facilities.

Approximately 99% of the energy we produce is generated by coal. DP&L’s share of CO₂ emissions at generating stations we own and co-own is approximately 14 million tons annually. If we are required to implement control of CO₂ and other GHGs at generation facilities, the cost to DPL and DP&L of such controls could be material.

NO_x and SO₂ Emissions CSAPR

Clean Air Interstate Rule/Cross-State Air Pollution Rule

The USEPA promulgated CAIR on March 10, 2005, which required allowance surrender for SO₂ and NO_x emissions from existing power stations located in 27 eastern states and the District of Columbia. CAIR contemplated two implementation phases. The first phase began in 2009 and 2010 for NO_x and SO₂, respectively. A second phase with additional allowance surrender obligations for both air emissions was scheduled to begin in 2015. To implement the required emission reductions for this rule, the states were to establish emission-allowance-based cap-and-trade programs. CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the USEPA.

In an attempt to conform to the Court’s decision, the USEPA issued CSAPR on July 6, 2011, but subsequent litigation resulted in CSAPR being vacated in 2012 and CAIR being reinstated pending the promulgation of a replacement rule.  On June 24, 2013, the U.S. Supreme Court agreed to review the D.C. Circuit Court’s decision to vacate CSAPR and on April 29, 2014, the U.S Supreme Court reversed the 2012

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decision and remanded the case back to the D.C. Circuit Court.  CSAPR was reinstated on October 23, 2014. The USEPA established new effective dates for compliance with the reduced emissions levels, beginning in 2015 with additional reductions in 2017. At this time, it is not possible to predict what impacts this action may have on our consolidated financial condition, results of operations or cash flows, but it is not expected to be material.

Climate Change Legislation and Regulation

On June 25, 2013, the President of the United States directed the USEPA to issue a new proposed rule establishing New Source Performance Standards for CO₂ emissions for newly constructed fossil-fueled EGUs larger than 25 MW by September 2013, and to issue a final rule in a timely fashion after considering all public comments.  The USEPA issued such new proposed rule in September 2013. The proposed rule anticipates that newly constructed fossil-fueled power plants generally would need to rely upon partial implementation of carbon capture and storage technology or other pollution control technology to meet the standard.

In his June 25, 2013, announcement, the President, as anticipated, also directed the USEPA to issue new standards, regulations, or guidelines, as appropriate, that address CO₂ emissions from existing power plants. The USEPA issued proposed rules establishing GHG performance standards for existing power plants under CAA Section 111(d) on June 2, 2014.  Under the proposed rule, states would be judged against state-specific carbon dioxide emissions targets beginning in 2020, with expected total U.S. power section emissions reduction of 30% from 2005 levels by 2030.  The proposed rule requires states to submit SIPs to meet the standards set forth in the rule by June 30, 2016, with the possibility of one or two-year extensions under certain circumstances.  The proposed rule was subject to a public comment process and the USEPA is expected to finalize it by July 2015.  Among other things, the Company could be required to make efficiency improvements to existing facilities. The impact, including the compliance costs, could be material to our consolidated financial condition or results of operations.

SB 221 Requirements

SB 221 and the implementation rules contained targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards. SB 310 which was passed in 2014 modified those standards slightly. The renewable energy portfolio, energy efficiency and demand reduction standards began in 2009 with increased percentage requirements each year thereafter. The annual targets for energy efficiency and peak demand reductions began in 2009 with annual increases. Energy efficiency programs are to save 22.3% by 2025 and peak demand reductions are expected to reach 7.75% by 2018 compared to a baseline energy usage. If any targets are not met, compliance penalties will apply, unless the PUCO makes certain findings that would excuse performance.

SB 221 also contains provisions for determining whether an electric utility has significantly excessive earnings. The PUCO issued general rules for calculating the earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings. DP&L was first subject to the SEET in 2013 based on 2012 earnings results, which did not have a material impact. Likewise, DP&L was found not to have excessive earnings in calendar year 2013. Through the ESP Order the PUCO established DP&L’s ROE SEET threshold at 12%. In future years, the SEET could have a material effect on our results of operations, financial condition and cash flows.

SB 221 also required that all Ohio distribution utilities file either an ESP or MRO. Under the MRO, a periodic competitive bid process will set the retail generation price after the utility demonstrates that it can meet certain market criteria and bid requirements. Also, under this option, utilities that still own generation in the state are required to phase-in the MRO over a period of not less than five years. An ESP may allow for adjustments to the SSO for costs associated with environmental compliance; fuel and purchased power; construction of new or investment in specified generating facilities; and the provision of standby and default service, operating, maintenance, or other costs including taxes. As part of its ESP, a utility is permitted to file an infrastructure improvement plan that will specify the initiatives the utility will take to rebuild, upgrade, or replace its electric distribution system, including cost recovery mechanisms. Both the MRO and ESP options involve a SEET based on the earnings of comparable companies with similar business and financial risks.

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On October 5, 2012, DP&L filed an ESP with the PUCO which was to be effective January 1, 2013. The plan was refiled to correct certain costs on December 12, 2012. The refiled plan requested approval of a non-bypassable charge that was designed to recover $137.5 million per year for five years from all customers. The ESP proposed a three-year, five-month transition to market, whereby a wholesale competitive bidding structure would be phased in to supply generation service to customers located in DP&L’s service territory that have not chosen an alternative generation supplier. An evidentiary hearing on this case was held March 18, 2013 through April 3, 2013. An order was issued by the PUCO on September 4, 2013, and a correction to that order was issued on September 6, 2013 (ESP Order).

The ESP Order stated that DP&L’s next ESP begins January 2014 and extends through May 31, 2017. The PUCO authorized DP&L to collect a non-bypassable Service Stability Rider (SSR) equal to $110 million per year for 2014 2016, with an opportunity to extend the charge through May 2017 if certain conditions were met. The ESP Order also directs DP&L to divest its generation assets no later than January 1, 2017 and sets DP&L’s SEET threshold at a 12% ROE. Beginning in 2014, DP&L was no longer permitted to supply 100% of the generation service to its SSO customers. Instead, the PUCO directed DP&L to phase-in the competitive bidding structure with 10% of DP&L’s SSO load sourced through the competitive bid starting in 2014, 60% in 2015, and 100% beginning January 1, 2016. The ESP Order approved DP&L’s rate proposal to bifurcate its transmission charges into a non-bypassable component, TCRR-N, and a bypassable component, TCRR-B. The ESP order also required DP&L to establish a $2.0 million per year shareholder funded economic development fund.

Applications for rehearing were filed several times throughout 2013 and 2014 and a final order on rehearing was issued on July 23, 2014. Several parties including DP&L appealed the orders in this case to the Ohio Supreme court.

Legal separation of DP&L’s generating facilities

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 or before January 1, 2017. Comments and reply comments were filed. DP&L amended its application on February 25, 2014 and again on May 23, 2014. Additional comments and reply comments were filed. 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 continues to look at multiple options to effectuate the separation including the transfer to an unregulated affiliate or through a sale process.

Competition and PJM Pricing

RPM Capacity Auction Price

The PJM RPM capacity base residual auction for the 2017/18 period cleared at a price of $120/MW-day for our RTO area.  The per megawatt-day prices for the periods 2016/17, 2015/16, and 2014/15 were $59/MW-day, $136/MW-day, and $126/MW-day, respectively, based on previous auctions. Future RPM auction results will be dependent not only on the overall supply and demand of generation and load, but may also be impacted by congestion as well as PJM s business rules relating to bidding for demand response and energy efficiency resources in the RPM capacity auctions. The SSO retail costs and revenues are included in the RPM rider. Therefore increases in customer switching cause more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation. We cannot predict the outcome of future auctions or customer switching but based on actual results attained in 2014, we estimate that a hypothetical increase or decrease of $10/MW-day in the capacity auction price would affect net income by approximately $6.4 million and $5.1 million for DPL and DP&L, respectively. These estimates do not, however, take into consideration the other factors that may affect the impact of capacity revenues and costs on net income such as the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load. These estimates are discussed further below under “—Market Risk—Commodity Pricing Rule”.

There are proposals from PJM pending before the FERC that would modify capacity markets including near-term modifications with respect to RPM and longer-term modifications that would phase-out RPM and replace it with a Capacity Performance (“CP”) program. Because the changes to the capacity markets proposed

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by PJM are still being evaluated by the FERC, the FERC has approved a waiver that allows PJM to delay the capacity auction that would have been held in May 2015.

Ohio Competitive Considerations and Proceedings

Since January 2001, DP&L’s electric customers have been permitted to choose their retail electric generation supplier. DP&L continues to have the exclusive right to provide delivery service in its state certified territory and the obligation to procure and provide SSO to customers that do not choose an alternative supplier; however, the supply of electricity for DP&L’s SSO customers is partially sourced through a competitive bid auction in 2014 and 2015, with 100% sourced through competitive bid starting January 2016. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.

Lower market prices for power have resulted in increased levels of competition to provide retail generation services. This in turn has led to CRES providers, including DPLER, having approximately 71% of 2014 total electric sales in DP&L’s service territory. DPLER, an affiliated company and one of the registered CRES providers, has been marketing generation services to DP&L customers.

The following table provides a summary of the number of electric customers and volumes provided by all CRES providers in our service territory during the years ended December 31, 2014, 2013 and 2012:

	Year ended December 31, 2014				Year ended December 31, 2013				Year ended December 31, 2012
	Electric Customers		Sales (in millions of kWh)		Electric Customers		Sales (in millions of kWh)		Electric Customers		Sales (in millions of kWh)
Supplied by DPLER		131,236		5,649		130,303		5,874		73,672		6,201
Supplied by non-affiliated CRES providers		110,536		4,365		87,951		3,471		79,936		1,981
Total supplied by CRES providers in DP&L’s service territory		241,772		10,014		218,254		9,345		153,608		8,182
Distribution customers/sales by DP&L in our service territory(1)		515,622		14,006		514,926		13,877		513,266		13,999

(1) The kWh sales include all distribution sales, including those whose power is supplied by DPLER and non-affiliated CRES providers.

The following tables provide a summary of the number of electric customers and volumes supplied by DPLER and non-affiliated CRES providers in our service territory during the three months ended March 31, 2015 and 2014:

	Three months ended March 31, 2015				Three months ended March 31, 2014
	Electric Customers		Sales (in millions of kWh)		Electric Customers		Sales (in millions of kWh)
Supplied by DPLER(1)		124,367		1,149		138,420		1,604
Supplied by non-affiliated CRES providers		116,568		1,413		90,593		999
Total in DP&L's service territory		240,935		2,562		229,013		2,603
Distribution customers/sales by DP&L in our service territory		516,324		3,756		515,748		3,827

(1) DPLER’s customer mix has shifted from high-volume industrial consumers to lower volume residential consumers.

The volumes supplied by DPLER represent approximately 40%, 42% and 44% of DP&L’s total distribution volumes during the years ended December 31, 2014, 2013 and 2012, respectively. The volumes supplied by DPLER represent approximately 31% and 42% of DP&L’s total distribution volumes during the three months ended March 31, 2015 and 2014, respectively. We currently cannot determine the extent to which customer switching to CRES providers will occur in the future and the effect this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows. For the year ended December 31, 2014, approximately 71% of DP&L’s load was supplied by CRES providers with DPLER supplying 56% of the switched load.

Several communities in DP&L’s service area have passed ordinances allowing the communities to become government aggregators for the purpose of offering retail generation service to their residents. To date, a

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number of communities have filed with the PUCO to initiate aggregation programs.  If a number of the larger communities move forward with aggregation in DP&L’s service area, it could have a material effect on our earnings. As discussed in “Business,” beginning January 1, 2016, customer switching will have no effect on DP&L’s financial condition. See “Risk Factors” for more information.

Fuel and Related Costs

Fuel and Commodity Prices

The coal market is a global market in which domestic prices are affected by international supply disruptions and demand balance. In addition, domestic issues like government-imposed direct costs and permitting issues are affecting mining costs and supply availability. Our approach is to hedge the fuel costs for our anticipated electric sales. We have substantially all of the total expected coal volume needed to meet our retail and wholesale sales requirements for 2015 under contract. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments and some are priced based on market indices. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled/forced outages and generation station mix. Due to the installation of emission controls equipment at certain commonly-owned units and barring any changes in the regulatory environment in which we operate, we expect to have balanced positions for SO₂, NO_x and renewable energy credits for 2015. If our suppliers do not meet their contractual commitments or we are not hedged against price volatility and we are unable to recover costs through the fuel and purchased power recovery rider, our results of operations, financial condition or cash flows could be materially affected.

Beginning January 2010, fuel price changes, including coal requirements and purchased power costs, associated with SSO load was reflected in the implementation of the fuel and purchased power recovery rider, subject to PUCO review. This fuel rider is in the process of being phased out as the SSO will be 100% sourced through the competitive bid process by 2016.  In August 2014, the PUCO issued an order in a case relating to review of DP&L’s fuel cost recovery mechanism for the calendar year 2012. The order included the disallowance of an immaterial amount of fuel costs. The impact of the order being issued was a reversal in the third quarter of 2014 of a previously established $2.6 million reserve. The audit report for calendar year 2013 had immaterial findings.

Financial Overview

The results of operations for DPL are discussed in more detail in the following pages.

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The following table summarizes the significant components of DPL’s Results of Operations for the years ended December 31, 2014, 2013 and 2012:

	Years ended December 31,
$ in millions	2014			2013			2012
Total operating revenues	$	1,763.0		$	1,636.9		$	1,668.4
Cost of revenues:
Fuel		304.5			366.7			361.9
Purchased power		592.6			389.0			342.1
Amortization of intangibles		1.2			7.1			95.1
Total cost of revenues		898.3			762.8			799.1
Total gross margin (1)		864.7			874.1			869.3
Operating expenses:
Operation and maintenance		388.3			396.7			406.4
Depreciation and amortization		139.8			132.9			125.4
General taxes		91.7			80.9			79.5
Goodwill impairment		135.8			306.3			1,817.2
Fixed-asset impairment		11.5			26.2			—
Other		(3.9	)		2.5			0.2
Total operating expenses		763.2			945.5			2,428.7
Operating income / (loss)		101.5			(71.4	)		(1,559.4	)
Investment income / (loss), net		0.9			1.4			2.5
Interest expense		(126.6	)		(124.0	)		(122.9	)
Charge for early redemption of debt		(30.9	)		(2.8	)		—
Other expense, net		(1.5	)		(2.9	)		(2.3	)
Loss before income taxes		(56.6	)		(199.7	)		(1,682.1	)
Income taxes		18.0			22.3			47.7
Net loss	$	(74.6	)	$	(222.0	)	$	(1,729.8	)

(1) 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.

Results of Operations - DPL Inc. – years ended December 31, 2014, 2013 and 2012

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

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Income Statement Highlights - DPL

	Years ended December 31,
	2014			2013			2012
	$ in millions
Revenues:
Retail	$	1,364.0		$	1,297.2		$	1,391.2
Wholesale		198.0			229.7			104.5
RTO revenue		81.9			77.9			92.2
RTO capacity revenues		109.2			28.7			74.5
Other revenues		10.8			10.6			11.0
Mark-to-market gains / (losses)(1)		(0.9	)		(7.2	)		(5.0	)
Total revenues		1,763.0			1,636.9			1,668.4
Cost of revenues:
Fuel		305.4			366.0			358.6
Losses / (gains) from sale of coal		(1.3	)		0.7			11.8
Mark-to-market losses / (gains)		0.4			—			(8.5	)
Net fuel cost		304.5			366.7			361.9
Purchased power:
Purchased power		328.2			243.9			181.7
RTO charges		154.2			111.9			101.5
RTO capacity charges		107.8			34.1			68.1
Mark-to-market losses / (gains)		2.4			(0.9	)		(9.2	)
Net purchased power		592.6			389.0			342.1
Amortization of intangibles		1.2			7.1			95.1
Total cost of revenues		898.3			762.8			799.1
Gross margins(2)	$	864.7		$	874.1		$	869.3
Gross margins as % of revenue		49	%		53	%		52	%
Operating income / (loss)	$	101.5		$	(71.4	)	$	(1,559.4	)

(1) These amounts represent the amortization of asset balances related to retail power contracts that were previously accounted for as derivatives, but in accordance with ASC 815 are no longer derivatives. The fair value of these contracts is to be amortized to earnings over the remaining term of the associated agreements.

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

DPL - Revenues

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

Degree days

	Years ended December 31,
	2014		2013		2012
Number of days
Heating degree days(1)		5,950		5,542		4,752
Cooling degree days(1)		977		1,062		1,264

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

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Since we plan to utilize our internal generating capacity to supply the needs of our retail customers within the DP&L service territory first, increases in on-system retail demand may decrease the volume of internal generation available to be sold in the wholesale market and vice versa. The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors affecting our wholesale sales volume each hour of the year include: wholesale market prices; our retail demand; retail demand elsewhere throughout the entire wholesale market area; our stations and other utility stations availability to sell into the wholesale market; and weather conditions across the multi-state region.  Our plan is to make wholesale sales when market prices allow for the economic operation of our generation facilities not being utilized to meet our retail demand or when margin opportunities exist between the wholesale sales and power purchase prices.

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

	2014 vs. 2013			2013 vs. 2012
	$ in millions
Retail
Rate	$	123.3		$	(70.0	)
Volume		(56.7	)		(33.3	)
Other		0.2			9.3
Total retail change		66.8			(94.0	)
Wholesale
Rate		(21.3	)		(8.5	)
Volume		(10.4	)		133.7
Total wholesale change		(31.7	)		125.2
RTO capacity and other
RTO capacity and other		84.5			(60.1	)
Other
Unrealized MTM		6.3			(2.2	)
Other		0.2			(0.4	)
Total revenue changes	$	126.1		$	(31.5	)

During the year ended December 31, 2014, Revenues increased $126.1 million, or 8%, to $1,763.0 million from $1,636.9 million in the same period of the prior year. This increase was primarily the result of higher average retail rates, increased RTO capacity revenues; offset by lower average wholesale rates and lower retail and wholesale volume.

· Retail revenues increased $66.8 million primarily due to a 9.5% increase in average retail rates which resulted from the PUCO approved service stability rider and recovery of various regulatory riders for market based costs. DP&L sales volume decreased 7.4% from prior year; however, this was partially offset by increased sales procured by DPLER and MC Squared outside our service territory, or off-system sales, which resulted in an overall 3.9% decrease in total DPL’s sales volume. The aforementioned impacts resulted in a favorable $123.3 million retail price variance and an unfavorable $56.7 million retail volume variance.

· Wholesale revenues decreased $31.7 million due to a 9.7% decrease in average wholesale prices and 4.5% reduction in wholesale volume due to increased outages in 2014, which resulted in an unfavorable wholesale price variance of $21.3 million and an unfavorable wholesale sales volume variance of $10.4 million.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $84.5 million compared to 2013. This increase was primarily a result of an $80.5 million increase in revenues realized from the PJM capacity auction and an increase of $4.0 million in RTO transmission and congestion revenues.

During the year ended December 31, 2013, Revenues decreased $31.5 million, or 2%, to $1,636.9 million from $1,668.4 million in the same period of the prior year. This decrease was primarily the result of decreased

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retail and wholesale average rates, decreased RTO capacity and other revenues, offset by increased retail and wholesale volume.

· Retail revenues decreased $94.0 million primarily due to decreased prices driven by customer switching from competition to provide transmission and generation services in our service territory. The DP&L sales volume decreased 13% from the prior year; however, the effect of sales procured by DPLER and MC Squared outside our service territory, or off-system sales, offset volume decreases resulting in an overall 1% increase in total DPL’s sales volume. The rates offered to the off-system customers are lower than the rates in our service territory causing an overall 8% decrease in average rates. There was a 16% decrease in cooling degree days to 1,062 from 1,264 in 2012, as well as a 17% increase in the number of heating degree days to 5,542 days from 4,752 days in 2012, therefore weather had a minimal impact. The above resulted in an unfavorable $70.0 million retail price variance and an unfavorable $33.3 million retail sales volume variance.

· Wholesale revenues increased $125.2 million primarily as a result of a 128% increase in wholesale sales volume due to customer switching, which makes more of our generation available for wholesale sales, including a 16% increase in total net generation by our power plants, offset slightly by a 3.6% decrease in average wholesale prices. This resulted in a favorable $133.7 million wholesale sales volume variance partially offset by an unfavorable wholesale price variance of $8.5 million.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $60.1 million. This decrease in RTO capacity and other revenues was the result of a $45.8 million decrease in revenues realized from the PJM capacity auction, and a $12.8 million decrease in RTO transmission and congestion revenues due to a 2012 settlement related to PJM SECA revenues.

DPL - Cost of Revenues

During the year ended December 31, 2014:

· Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $62.2 million, or 17%, primarily due to a 13% decrease in internal generation as a result of increased outages combined with lower average fuel prices.

· Net purchased power increased $203.6 million, or 52%, compared to 2013. This was driven by an increase in RTO capacity and other costs of $116.0 million which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. RTO capacity prices are set by an annual auction. This increase also includes the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. In addition, purchase power volume increased 21% as a result of increased outages at our generating stations during 2014 and average purchased power prices increased 11%. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

· Amortization of intangibles decreased due to certain customer contract intangibles recognized at the merger date becoming fully amortized.

During the year ended December 31, 2013:

· Net fuel costs increased $4.8 million, or 1%, compared to 2012, primarily due to increased fuel costs and decreased mark-to-market gains partially offset by decreased losses from the sale of coal. There was a 16% increase in the volume of generation at our stations and no fuel related mark-to-market gains or losses in 2013 compared to $8.5 million of gains in 2012. Partially offsetting these increases were $0.7 million in realized losses from the sale of coal in 2013, compared to $11.8 million of realized losses from the same period in 2012.

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· Net purchased power increased $46.9 million, or 14%, compared to the same period in 2012 due largely to increased purchased power costs of $62.2 million, $48.3 million due to increased volume and $13.8 million due to higher average market prices for purchased power. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities. Partially offsetting these increases were decreased RTO capacity and other charges of $23.6 million which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. RTO capacity prices are set by an annual auction. This decrease also includes the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges.

· Amortization of intangibles decreased in 2013 compared to 2012 primarily due to the full amortization of the ESP during 2012.

DPL - Operation and Maintenance

	2014 vs. 2013
	$ in millions
Low-income payment program(1)	$	(10.1	)
Competitive retail operations		(4.7	)
Health Insurance and disability		(4.1	)
Deferred compensation liability		(1.5	)
Generating facilities operating and maintenance expenses		5.6
Maintenance of overhead transmission and distribution		5.2
Alternative energy and energy efficiency programs(1)		2.7
Other, net		(1.5	)
Total operation and maintenance expense	$	(8.4	)

(1) There is a corresponding increase / (decrease) in revenues associated with these programs resulting in no impact to net income.

During the year ended December 31, 2014, operation and maintenance expense decreased $8.4 million, or 2%, compared to the same period in 2013. This variance was primarily the result of:

· decreased expenses for the low-income payment program which are funded by the USF revenue rate rider;

· decreased marketing, customer maintenance and labor costs associated with the competitive retail business as a result of decreased sales volume;

· decreased health insurance due to cost decreases as well as a reduction in the disability reserve as a result of the 2014 actuarial study; and

· decreased deferred compensation costs.

These decreases were partially offset by:

· increased maintenance expenses at our generating facilities;

· increased expenses related to the maintenance of overhead transmission and distribution lines; and

· increased expenses relating to alternative energy and energy efficiency programs.

	2013 vs. 2012
	$ in millions
Generating facilities operating and maintenance expenses	$	(19.9	)
Low-income payment program(1)		(3.8	)
Pension		(1.4	)
Competitive retail operations		13.3
Health Insurance		3.0
Other, net		(0.9	)
Total operation and maintenance expense	$	(9.7	)

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(1) There is a corresponding increase in Revenues associated with this program resulting in no impact to Net income.

During the year ended December 31, 2013, Operation and maintenance expense decreased $9.7 million, or 2%, compared to the same period in 2012. This variance was primarily the result of:

· decreased expenses for generating facilities largely due to outages related to maintenance activities in the first and second quarters of 2012 at jointly owned production units relative to the same periods in 2013;

· decreased expense associated with the USF revenue rate rider, which provides assistance to low-income retail customers; and

· lower pension expenses primarily related to changes in plan assumptions, specifically a higher discount rate.

These decreases were partially offset by:

· increased marketing, customer maintenance and labor costs associated with the competitive retail business as a result of increased sales volume and number of customers; and

· increased health insurance due to cost increases as well as more employees going on to long-term disability as compared to the same period in 2013.

DPL - Depreciation and Amortization

During the year ended December 31, 2014, Depreciation and amortization expense increased $6.9 million, or 5%, compared to 2013. The increase primarily reflects additional investments in fixed assets.

During the year ended December 31, 2013, Depreciation and amortization expense increased $7.5 million, or 6%, compared to 2012. The increase primarily reflects additional investments in fixed assets.

DPL - General Taxes

During the year ended December 31, 2014, General taxes increased $10.8 million, or 13%, compared to 2013. The increase was primarily due to an adjustment to the 2013 estimated property tax liability to adjust estimates to actual payments that were made in 2014, higher property tax accruals for 2014 compared to 2013 and a favorable determination of $1.6 million from the Ohio gross receipts appeal in 2013.

During the year ended December 31, 2013, General taxes increased $1.4 million, or 2%, compared to 2012. This increase was primarily due to higher property tax accruals in 2013 compared to 2012 partially offset by a favorable determination of $1.6 million from the Ohio gross receipts tax appeal in 2013.

DPL - Goodwill Impairment

During the year ended December 31, 2014, DPL recorded an impairment of goodwill of $135.8 million. See Note 5 of notes to DPL’s consolidated financial statements.

During the year ended December 31, 2013, DPL recorded an impairment of goodwill of $306.3 million. See Note 5 of notes to DPL’s consolidated financial statements.

DPL - Interest Expense

During the year ended December 31, 2014, Interest expense increased $2.6 million, or 2%, compared to 2013 due primarily to reduced amortization of debt premium (which offsets interest expense) partially offset by decreased interest rates on DP&L’s senior secured bonds.

During the year ended December 31, 2013, Interest expense decreased $1.1 million, or 1%, compared to 2012 due primarily to decreased interest due to reductions in debt and decreased interest rates on DP&L’s senior secured bonds partially offset by reduced amortization of debt premium (which offsets interest expense).

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DPL - Income Tax Expense

During the year ended December 31, 2014, Income tax expense decreased $4.3 million compared to 2013 primarily due to lower pre-tax income (excluding the effect of the goodwill impairment), a 2014 deferred tax adjustment related to the expiration of the statutes of limitation on the 2010 tax year and a decrease in the tax benefits of Internal Revenue Code Section 199 in 2014.

During the year ended December 31, 2013, Income tax expense decreased $25.4 million compared to 2012 primarily due to lower pre-tax income (excluding the effect of the goodwill impairment), a 2013 deferred tax adjustment related to the expiration of the statutes of limitation on the 2007, 2008 and 2009 tax years, an increase in the tax benefits of Internal Revenue Code Section 199 in 2013 and a 2012 adjustment to state deferred taxes.

Results of Operations - DPL Inc. – three months ended March 31, 2015 and 2014

The following table summarizes the significant components of DPL’s Results of Operations for the three months ended March 31, 2015 and 2014:

	Three months ended
	March 31,
$ in millions	2015			2014
Revenues:
Retail	$	338.9		$	373.6
Wholesale		94.6			49.4
RTO revenues		19.2			26.7
RTO capacity revenues		39.1			8.4
Other revenues		2.8			2.7
Other mark-to-market losses		(0.1	)		(0.5	)
Total revenues		494.5			460.3
Cost of revenues:
Fuel costs		76.7			90.1
Gains from the sale of coal		(0.2	)		(0.2	)
Mark-to-market losses / (gains)		(0.1	)		0.1
Total fuel		76.4			90.0
Purchased power		126.2			106.9
RTO charges		33.1			51.5
RTO capacity charges		33.0			9.9
Mark-to-market losses		1.9			5.8
Total purchased power		194.2			174.1
Amortization of intangibles		—			0.3
Total cost of revenues		270.6			264.4
Gross margin (a)	$	223.9		$	195.9
Gross margin as a percentage of revenues		45	%		43	%
Operating income / (loss)	$	72.6		$	(119.3	)

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

DPL – Revenues

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

	Three months ended
	March 31,
	2015		2014
Heating degree days (a)		3,241		3,357
Cooling degree days (a)		—		—

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

Since we plan to utilize our internal generating capacity to supply our retail customers’ needs first, increases in retail demand may decrease the volume of internal generation available to be sold in the wholesale market and vice versa. The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting our wholesale sales volume each hour of the year include: wholesale market prices; our retail demand; retail demand elsewhere throughout the entire wholesale market area; our plants’ and non-affiliated utility plants’ availability to sell into the wholesale market; and weather conditions across the multi-state region. Our plan is to make wholesale sales when market prices allow for the economic operation of our generation facilities not being utilized to meet our retail demand or when margin opportunities exist between the wholesale sales and power purchase prices.

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

	Three months ended
	March 31,
$ in millions	2015 vs. 2014
Retail
Rate	$	15.6
Volume		(45.8	)
Other miscellaneous		(4.5	)
Total retail change		(34.7	)
Wholesale
Rate		28.2
Volume		17.0
Total wholesale change		45.2
RTO capacity & other
RTO capacity and other revenues		23.3
Other
Unrealized MTM		0.4
Total other revenue		0.4
Total revenues change	$	34.2

For the three months ended March 31, 2015, Revenues increased $34.2 million to $494.5 million from $460.3 million in the same period of the prior year. This increase was primarily the result of increased wholesale and RTO capacity and other revenues, partially offset by lower retail revenue. The changes in the components of revenue are discussed below:

· Retail revenues decreased $34.7 million primarily due to decreased volume driven by a loss of DPLER customers both within and outside of DP&L’s service territory, although DP&L continues to provide distribution service to all customers within its service territory. Also contributing to the decrease is a 4% decrease in heating degree days compared to 2014 as well as lower retail revenue for SSO customers as the competitive auction rate, which represents 60% of our SSO load in 2015 compared to 10% in 2014, is lower than our non-auction generation rate. Partially offsetting these decreases are increased DP&L retail revenue due to recovery of previously deferred costs and increased DPLER average rates.

· Wholesale revenues increased $45.2 million as a result of a $28.2 million increase in wholesale price and a favorable $ 17.0 million volume variance. The year over year price increase is resulting from the impact of realized derivative losses in 2014 largely due to extreme weather during January of 2014. The volume increase was driven by 60% of SSO load being served through the competitive bid process compared to 10% during 2014 allowing excess generation to be sold in the wholesale market. This was partially offset by a 20% decrease in net generation from DP&L’s co-owned and operated plants primarily due to the 2014 sale of East Bend and closing of Beckjord as well as increased outages.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $23.3 million compared to the same period in 2014. This increase was primarily the result of a $30.7 million increase in revenues realized from PJM capacity auction offset by a $7.5 million decrease in RTO transmission and congestion revenue, as 2014 congestion revenue charges were higher due to extreme weather. The capacity prices that became effective in June 2014 were $126/MWh, compared to $28/MWh in June 2013.

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DPL – Cost of Revenues

For the three months ended March 31, 2015:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $13.6 million, or 15%, compared to the same period in 2014, primarily due to a 20% decrease in internal generation at our plants offset by a 6% increase in average fuel cost per MWh.

· Net purchased power increased $20.1 million, or 12%, compared to the same period in 2014 due largely to a $24.7 million volume increase driven by increased power purchased to source our SSO load through the competitive bid process as well as decreased internal generation and increased RTO capacity charges of $23.1 million. These increases were partially offset by an $18.4 million decrease in other RTO charges, a $5.4 million decrease due to lower average prices compared to 2014 and a $3.9 million decrease in net MTM losses. RTO capacity prices are set by an annual auction. The capacity prices that became effective in June 2014 were $126/MWh, compared to $28/MWh in June 2013. RTO charges are incurred as a member of PJM and include costs associated with our load obligations for retail customers. We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.

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DPL – Operation and Maintenance

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

	Three months ended
	March 31,
$ in millions	2015 vs. 2014
Low-income payment program (1)	$	(6.1	)
Competitive retail operations		(2.6	)
Alternative energy and energy efficiency programs (1)		(2.2	)
Health Insurance		(1.0	)
Other, net		(1.1	)
Total change in operation and maintenance expense	$	(13.0	)

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

During the three months ended March 31, 2015, Operation and maintenance expense decreased $13.0 million, compared to the same period in the prior year. This variance was primarily the result of:

· decreased expenses for the low-income payment program which is funded by the USF revenue rate rider,

· decreased marketing, customer maintenance and labor costs associated with the competitive retail business,

· decreased expenses relating to alternative energy and energy efficiency programs, and

· decreased health insurance due to cost decreases.

DPL – Depreciation and Amortization

For the three months ended March 31, 2015, Depreciation and amortization expense decreased $0.3 million compared to the same period in the prior year as a result of an adjustment of $1.2 million to the AROs for the Hutchings plant in 2014 partially offset by routine plant additions and replacements.

DPL – General Taxes

For the three months ended March 31, 2015, General taxes decreased $3.5 million compared to the same period in the prior year. The decrease was primarily due to a 2014 adjustment to the 2013 estimated property tax liability to adjust estimates to actual payments made in 2014 partially offset by higher property tax accruals for 2015 compared to 2014.

DPL – Interest Expense

Interest expense recorded during the three months ended March 31, 2015 decreased $0.3 million compared to the same period in the prior year.  This was primarily driven by decreased bond interest of $1.3 million as a result of debt prepayments and the refinancing of certain debt partially offset by an increase related to the recovery of previously deferred carrying costs on regulatory assets of $1.1 million.

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DPL – Income Tax Expense

For the three months ended March 31, 2015, Income tax expense decreased $86.1 million compared to the same period in 2014, primarily due to the application of an estimated annual Effective Tax Rate (ETR) approach in accordance with ASC 740-270, Interim Reporting. The ETR for 2015 is estimated to be 31.1% as compared to the estimated ETR applied to the prior year period of (65.8)%. The primary factor impacting the 2014 ETR was the non-deductible goodwill impairment recorded in the first quarter of 2014.

Results of Operations by Segment – DPL Inc.

DPL’s two segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its competitive retail electric service subsidiary. These segments are discussed further below:

Utility Segment

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and distribute electricity to residential, commercial, industrial and governmental customers. DP&L generates electricity at five coal-fired power stations and distributes electricity to more than 516,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. Beginning in 2014, DP&L was required to procure 10% of the power for SSO customers through a competitive bid process, with the percentage increasing each year, reaching 100% by January 1, 2016. Further, in December 2013, DP&L filed a plan with the PUCO to sell or transfer its generation assets by January 1, 2017. DP&L also sells 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 rates for its generation business are deemed competitive under Ohio law.

Competitive Retail Segment

The Competitive Retail segment is comprised of DPLER’s competitive retail electric service business. Until April 1, 2015, DPLER’s retail electric service business included its wholly-owned subsidiary, MC Squared, which was recently sold in a stock purchase transaction. See “Summary—Recent Developments.” DPLER sells retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER. The Competitive Retail segment sells electricity to approximately 143,000 customers currently located throughout Ohio. 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 are based on the market prices for wholesale power. The price approximates market prices for wholesale power at the inception of each customer s contract. The Competitive Retail segment has no transmission or generation assets. The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.

Other

Included within Other are other businesses that do not meet the GAAP requirements for separate disclosure as reportable segments as well as certain corporate costs including interest expense on DPL’s debt.

Management evaluates segment performance based on gross margin. See Note 14 of notes to DPL’s consolidated financial statements for further discussion of DPL’s reportable segments.

Results of Operations by Segment – DPL Inc. – years ended December 31, 2014, 2013 and 2012

The following table presents DPL’s gross margin by business segment for:

	Years ended December 31,
	2014			2013			2012
	$ in millions
Utility	$	771.0		$	807.1		$	867.4
Competitive Retail		41.8			51.9			68.6
Other		55.4			18.7			(63.3	)
Adjustments and Eliminations		(3.5	)		(3.6	)		(3.4	)
Total consolidated	$	864.7		$	874.1		$	869.3

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The financial condition, results of operations and cash flows of the Utility segment are identical in all material respects and for all periods presented to those of DP&L which are included in this prospectus. We do not believe that additional discussions of the financial condition and results of operations of the Utility segment would enhance an understanding of this business since these discussions are already included under the DP&L discussions below.

Income Statement Highlights – Competitive Retail Segment

	Years ended December 31,
	2014			2013			2012
	$ in millions
Revenues:
Retail	$	533.1		$	518.8		$	496.7
RTO and other		0.5			(7.2	)		(3.6	)
Total revenues		533.6			511.6			493.1
Cost of revenues:
Purchased power		491.8			459.7			424.5
Gross margins(1)		41.8			51.9			68.6
Operation and maintenance expense		33.3			38.0			24.7
Other expense		3.3			3.1			3.0
Total expenses		36.6			41.1			27.7
Earnings from operations		5.2			10.8			40.9
Income tax expense		2.0			4.2			18.1
Net income	$	3.2		$	6.6		$	22.8
Gross margin as a % of revenues		8	%		10	%		14	%

(1) 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.

Competitive Retail Segment - Revenue

During the year ended December 31, 2014, the segment’s retail revenue increased $14.3 million or 3%, compared to 2013. The increase was primarily due to higher average retail rates for off-system sales and increased off-system sales volume, partially offset by lower on-system sales volume due to customer switching to unaffiliated third-party CRES providers. RTO and other revenues increased primarily due to the derivative-related amortization in 2013. The Competitive Retail segment sold approximately 9,717 million kWh of power to 260,000 customers in 2014 compared to approximately 9,733 million kWh of power to 308,000 customers during the same period of the prior year.

During the year ended December 31, 2013, the segment’s retail revenues increased $22.1 million, or 4%, compared to 2013. The increase was primarily due to an $84.8 million positive volume variance primarily due to sales growth outside of DP&L’s service territory in both Ohio and Illinois. The increased volume was partially offset by a $62.7 million negative price variance as increased competition in the competitive retail electric service business in the state of Ohio has resulted in decreased retail prices. The Competitive Retail segment sold approximately 9,733 million kWh of power to approximately 308,000 customers compared to

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approximately 8,315 million kWh of power to approximately 198,000 customers during the same period of the prior year.

Competitive Retail Segment - Purchased Power

During the year ended December 31, 2014, the segment’s purchased power costs increased $32.1 million, or 7%, due to higher prices, partially offset by a slight volume decline.

During the year ended December 31, 2013, the Competitive Retail segment purchased power increased $35.2 million, or 7%, compared to 2013 primarily due to increased purchased power volume required to satisfy an increase in customer base as described in the revenue section above.

Competitive Retail Segment - Operation and Maintenance

DPLER’s operation and maintenance expenses include employee-related expenses, marketing, accounting, information technology, payroll, legal and other administration expenses.

The $4.7 million, or 12%, decrease in operation and maintenance expense in 2014 compared to 2013 is reflective of decreased marketing and customer maintenance costs associated with the decreased number of customers.

The $13.3 million, or 54%, increase in operation and maintenance expense in 2013 compared to 2012 is reflective of increased marketing and customer maintenance costs associated with the increased sales volume and number of customers.

Results of Operations by Segment – DPL Inc. – three months ended March 31, 2015 and 2014

The following table presents DPL’s gross margin by business segment:

	Three months ended
	March 31,						Increase /
	2015			2014			(Decrease)
Utility	$	202.3		$	179.8		$	22.5
Competitive Retail		10.6			8.2			2.4
Other		11.9			8.8			3.1
Adjustments and eliminations		(0.9	)		(0.9	)		-
Total consolidated	$	223.9		$	195.9		$	28.0

The financial condition, results of operations and cash flows of the Utility segment are identical in all material respects, and for both periods presented, to those of DP&L. We do not believe that additional discussions of the financial condition and results of operations of the Utility segment would enhance an understanding of this business since these discussions are already included under the DP&L discussions following.

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Income Statement Highlights – Competitive Retail Segment

	Three months ended
	March 31,						Increase /
$ in millions	2015			2014			(Decrease)
Revenues:
Retail	$	121.8		$	148.9		$	(27.1	)
RTO and other		0.5			(0.5	)		1.0
Total revenues		122.3			148.4			(26.1	)
Cost of revenues:
Purchased power		111.7			140.2			(28.5	)
Gross margins (a)		10.6			8.2			2.4
Operation and maintenance expense		6.7			9.4			(2.7	)
Other expenses		1.0			0.9			0.1
Total expenses		7.7			10.3			(2.6	)
Earnings before income tax		2.9			(2.1	)		5.0
Income tax expense		1.3			(0.7	)		2.0
Net income	$	1.6		$	(1.4	)	$	3.0
Gross margin as a percentage of revenues		9	%		6	%

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

Competitive Retail Segment – Revenue

For the three months ended March 31, 2015, the segment’s retail revenues decreased $26.1 million, or 18%, compared to the prior year. The decrease was primarily due to decreased customer contract renewals in both the Illinois and Ohio markets combined with weather related volume decreases. The Competitive Retail segment sold approximately 2,048 million kWh of power to approximately 259,000 customers for the three months ended March 31, 2015 compared to approximately 2,782 million kWh of power to more than 322,000 customers during the same period of the prior year.

Competitive Retail Segment – Purchased Power

For the three months ended March 31, 2015, the segment’s purchased power decreased $28.5 million, or 20%, compared to the same period in 2014 due to decreased purchased power volumes required to meet customer requirements, partially offset by higher average prices. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L.

Competitive Retail Segment – Operation and Maintenance

For the three months ended March 31, 2015, DPLER’s operation and maintenance expenses decreased as a result of decreased sales volume.

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Competitive Retail Segment – Income Tax Expense

For the three months ended March 31, 2015, the segment’s income tax expense increased compared to the same period in the prior year due to higher pre-tax income.

Results of Operations - Utility Segment (DP&L) – years ended December 31, 2014, 2013 and 2012

Income Statement Highlights - DP&L

	Years ended December 31,
	2014			2013			2012
	$ in millions
Revenues:
Retail	$	834.2		$	782.0		$	898.4
Wholesale		666.0			671.3			483.7
RTO revenues		77.6			74.5			88.5
RTO capacity revenues		90.5			24.0			63.4
Mark-to-market gains / (losses)		–			(0.3	)		(2.2	)
Total revenues		1,668.3			1,551.5			1,531.8
Cost of revenues:
Cost of fuel:
Fuel		315.8			361.8			351.6
Losses / (gains) from sale of coal		(1.3	)		0.7			11.8
Gains from sale of emission allowances		–			–			(0.1	)
Mark-to-market (gains) / losses		0.4			–			(8.4	)
Net fuel costs		314.9			362.5			354.9
Purchased power:
Purchased power		323.7			236.9			151.6
RTO charges		150.4			109.8			98.8
RTO capacity charges		106.7			33.9			64.1
Mark-to-market (gains) / losses		1.6			1.3			(5.0	)
Net purchased power		582.4			381.9			309.5
Total cost of revenues		897.3			744.4			664.4
Gross margins(1)	$	771.0		$	807.1		$	867.4
Gross margins as a % of revenues		46	%		52	%		57	%
Operating income	$	188.8		$	139.9		$	184.8

(1) 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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DP&L - Revenues

The following table provides a summary of changes in DP&L’s Revenues from prior periods:

	2014 vs. 2013			2013 vs. 2012
Retail
Rate	$	108.4		$	(7.3	)
Volume		(55.7	)		(118.5	)
Other		(0.5	)		9.4
Total retail change		52.2			(116.4	)
Wholesale
Rate		6.6			(64.5	)
Volume		(11.9	)		252.1
Total wholesale change		(5.3	)		187.6
RTO capacity and other
RTO capacity and other revenues		69.6			(53.4	)
Other
Unrealized MTM		0.3			1.9
Total revenues change	$	116.8		$	19.7

During the year ended December 31, 2014, revenues increased $116.8 million, or 8%, to $1,668.3 million from $1,551.5 million in the prior year.  This increase was primarily the result of higher average retail rates and increased RTO capacity revenues; partially offset by lower retail and wholesale volume.

· Retail revenues increased $52.2 million due to a 15% increase in average retail rates which resulted from the PUCO approved service stability rider and recovery of various regulatory riders for market based costs. Retail volume decreased 7% overall due to a 26% increase in the percentage of volume in the DP&L service territory being supplied by third-party CRES providers. DP&L continues to provide distribution services to these customers but the volumes are not recorded. Heating degree days increased by 408, or 7%, while cooling degree days decreased 85, or 8%, compared to 2013. During 2014, 31% of DP&L’s distribution sales were supplied by third-party CRES providers. As we only have distribution revenue on these sales, the weather impact is less than the weather impact on SSO sales. The above resulted in a favorable $108.4 million retail price variance partially offset by an unfavorable $55.7 million retail sales volume variance.

· Wholesale revenues decreased $5.3 million as a result of an $11.9 million decrease in wholesale sales volume, partially offset by a favorable $6.6 million price variance. Although customer switching in the DP&L service territory resulted in increased generation available to sell in the wholesale market, there was a 13% decrease in net generation available from DP&L’s co-owned and operated generation plants due to higher outages which resulted in an overall decrease in wholesale sales volume.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $69.6 million. This increase was primarily the result of a $66.5 million increase in revenues realized from the PJM capacity auction and an increase of $3.1 million in RTO transmission and congestion revenues.

During the year ended December 31, 2013, Revenues increased $19.7 million, or 1%, to $1,551.5 million from $1,531.8 million in the prior year. This increase was primarily the result of higher wholesale sales volumes. The revenue components for the year ended December 31, 2013 compared to 2012 are further discussed below.

· Retail revenues decreased $116.4 million primarily due to a 13% decrease in retail sales volumes compared to the prior year which was a result of customer switching due to increased levels of competition to provide transmission and generation services in our service territory. There was a 16%

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decrease in cooling degree days to 1,062 days from 1,264 days in 2012, as well as a 17% increase in the number of heating degree days to 5,542 days from 4,752 days in 2012, therefore weather had a minimal impact. Although DP&L had a number of customers that switched their retail electric service from DP&L to CRES providers, DP&L continued to provide distribution services to those customers within its service territory. Average retail rates decreased slightly overall. The remaining distribution services provided by DP&L were billed at a lower average rate resulting in a slight reduction of total average retail rates. The above resulted in an unfavorable $118.5 million retail sales volume variance and an unfavorable $7.3 million retail price variance, partially offset by a $7.0 million shared savings accrual related to DP&L energy efficiency programs.

· Wholesale revenues increased $187.6 million as a result of an increase in wholesale sales volume which was largely a result of customer switching discussed in the immediately preceding paragraph. Customer switching in the DP&L service territory has resulted in increased generation available to sell in the wholesale market. Also contributing was a 17% increase in net generation available from DP&L’s co-owned and operated generation plants. These increases were partially offset by a 9% decrease in average wholesale rates. These resulted in a favorable $252.1 million wholesale volume variance offset by a $64.5 million unfavorable wholesale price variance.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $53.4 million. This decrease in RTO capacity and other revenues was primarily the result of a $39.4 million decrease in revenues realized from the PJM capacity auction, and a $12.8 million decrease in RTO transmission and congestion revenues due to a 2012 settlement related to PJM SECA revenues.

DP&L - Cost of Revenues

During the year ended December 31, 2014:

· Net fuel costs decreased $47.6 million, or 13%, due to a 13% decrease in internal generation due to increased outages combined with lower average fuel prices, partially offset by costs associated with the early termination of a fuel contract.

· Net purchased power increased $200.5 million, or 53%, compared to the same period in 2013. This was driven by increased RTO capacity and other costs of $113.4 million which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. RTO capacity prices are set by an annual auction. This increase also includes the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. In addition, purchased power volume increased 21% as a result of increased outages at our generating stations during 2014 and average purchased power prices increased 12%. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

During the year ended December 31, 2013:

· Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $7.6 million, or 2%, compared to 2012, primarily due to increased fuel costs and decreased mark-to-market gains on coal contracts partially offset by decreased losses from the sale of coal. During the year ended December 31, 2013, there was a 17% increase in the volume of generation at our stations and no fuel related mark-to-market gains or losses compared to $8.4 million of gains in 2012. Partially offsetting these increases were $0.7 million in realized losses from the sale of coal, compared to $11.8 million of realized losses from the same period in 2012.

· Net purchased power increased $72.4 million, or 23%, compared to the same period in 2012 due largely to increased purchased power costs of $85.3 million, $74.0 million due to increased volume and an increase of $11.9 million due to higher average market prices for purchased power. Purchased power volume increased due to power purchased to supply increased off-system sales. We purchase

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power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities. Partially offsetting these increases were decreased RTO capacity and other charges of $19.2 million which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. RTO capacity prices are set by an annual auction. This decrease also includes the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges.

DP&L - Operation and Maintenance

	2014 vs. 2013
	$ in millions
Low-income payment program(1)	$	(10.1	)
Health Insurance and disability		(4.7	)
Pension		(1.5	)
Deferred compensation liability		(1.5	)
Generating facilities operating and maintenance expenses		5.7
Maintenance of overhead transmission and distribution		5.2
Alternative energy and energy efficiency programs(1)		1.6
Other, net		(3.6	)
Total operation and maintenance expense	$	(8.9	)

(1) There is a corresponding increase / (decrease) in Revenues associated with these programs resulting in no impact to Net income.

During the year ended December 31, 2014, Operation and maintenance expense decreased $8.9 million, or 2%, compared to 2013. This variance was primarily the result of:

· decreased expenses for the low-income payment program which is funded by the USF revenue rate rider;

· decreased health insurance due to cost decreases as well as a reduction in the disability reserve as a result of the 2014 actuarial study;

· lower pension expenses primarily related to changes in plan assumptions, specifically a higher discount rate; and

· decreased deferred compensation costs.

These decreases were partially offset by:

· increased maintenance expenses at our generating facilities;

· increased expenses related to the maintenance of overhead transmission and distribution lines; and

· increased expenses relating to alternative energy and energy efficiency programs.

	2013 vs. 2012
	$ in millions
Generating facilities operating and maintenance expenses	$	(19.8	)
Low-income payment program(1)		(3.8	)
Pension		(2.2	)
Health Insurance		3.0
Other, net		(1.0	)
Total operation and maintenance expense	$	(23.8	)

(1) There is a corresponding increase in Revenues associated with these programs resulting in no impact to Net income.

During the year ended December 31, 2013, Operation and maintenance expense decreased $23.8 million, or 6%, compared to 2012. This variance was primarily the result of:

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· decreased expenses for generating facilities largely due to outages related to maintenance activities in the first and second quarters of 2012 at jointly owned production units relative to the same periods in 2013;

· decreased expense associated with the USF revenue rate rider, which provides assistance for low-income retail customers; and

· lower pension expenses primarily related to changes in plan assumptions, specifically a higher discount rate.

These decreases were partially offset by:

· increased health insurance due to cost increases as well as more employees going on long-term disability as compared to the same period in 2013.

DP&L - Depreciation and Amortization

During the year ended December 31, 2014, Depreciation and amortization expense increased $4.6 million, or 3%, compared to 2013. The increase primarily reflects additional investments in fixed assets.

During the year ended December 31, 2013, Depreciation and amortization expense decreased $1.1 million, or 1%, compared to 2012. The decrease primarily reflects the full-year effect of a reduction of approximately $1.8 million related to a decrease in plant values as a result of impairment in the value of certain electric generating stations in the third quarter of 2012, partially offset by investments in plant and equipment.

DP&L - General Taxes

During the year ended December 31, 2014, General taxes increased $11.3 million, or 15%, compared to 2013. The increase was primarily due to an adjustment to the 2013 estimated property tax liability to adjust estimates to actual payments that were made in 2014, higher property tax accruals for 2014 compared to 2013 and a favorable determination of $1.6 million from the Ohio gross receipts tax appeal in 2013.

During the year ended December 31, 2013, General taxes increased $2.0 million, or 3%, compared to 2012. This increase was primarily the result of higher property tax accruals in 2013 compared to 2012 partially offset by a favorable determination of $1.6 million from the Ohio gross receipts tax appeal in 2013.

DP&L - Fixed-asset Impairment and gain on asset sale

During the year ended December 31, 2014, DP&L recorded a gain of $4.5 million on the sale of its interest in the East Bend generating station.

During the year ended December 31, 2013, DP&L had a fixed-asset impairment of $86.0 million related to the Conesville and East Bend generating stations.

DP&L - Interest Expense

During the year ended December 31, 2014, interest expense decreased $3.3 million or 9% compared to 2013 due to a reduction in outstanding debt and lower interest rates on DP&L’s senior secured bonds.

During the year ended December 31, 2013, interest expense decreased $1.9 million or 5% compared to 2012 due to a reduction in outstanding debt and lower interest rates on DP&L’s senior secured bonds.

DP&L - Income Tax Expense

During the year ended December 31, 2014, Income tax expense increased $21.1 million compared to 2013 primarily due to increases in pre-tax income, a 2014 deferred tax adjustment related to the expiration of the statutes of limitation on the 2010 tax year and a decrease in the tax benefits of Internal Revenue Code Section 199 in 2014.

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During the year ended December 31, 2013, Income tax expense decreased $36.5 million compared to 2012 primarily due to decreases in pre-tax income, a 2013 deferred tax adjustment related to the expiration of the statutes of limitation on the 2007, 2008 and 2009 tax years and an increase in the tax benefits of Internal Revenue Code Section 199 in 2013 and a 2012 adjustment to state deferred taxes.

Results of Operations - Utility Segment (DP&L) – three months ended March 31, 2015 and 2014

Income Statement Highlights – DP&L

	Three months ended
	March 31,
$ in millions	2015			2014
Revenues:
Retail	$	218.0		$	225.4
Wholesale		192.7			175.7
RTO revenues		18.3			24.0
RTO capacity revenues		32.3			7.0
Total revenues		461.3			432.1
Cost of revenues:
Fuel costs		69.6			84.4
Gains from the sale of coal		(0.2	)		(0.2	)
Mark-to-market losses / (gains)		(0.1	)		0.1
Total fuel		69.3			84.3
Purchased power		125.2			104.5
RTO charges		29.9			48.0
RTO capacity charges		32.7			9.8
Mark-to-market losses		1.9			5.7
Total purchased power		189.7			168.0
Total cost of revenues		259.0			252.3
Gross margin (a)	$	202.3		$	179.8
Gross margin as a percentage of revenues		44	%		42	%
Operating Income	$	60.3		$	21.3

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

DP&L – Revenues

Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, DP&L’s retail sales volume is impacted by the number of heating and cooling degree days occurring during a year. Since DP&L plans to utilize its internal generating capacity to supply its retail customers’ needs first, increases in retail demand will decrease the volume of internal generation available to be sold in the wholesale market and vice versa.

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The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting DP&L’s wholesale sales volume each hour throughout the year include: wholesale market prices, DP&L’s retail demand and retail demand elsewhere throughout the entire wholesale market area, DP&L and non-DP&L plants’ availability to sell into the wholesale market and weather conditions across the multi-state region. DP&L’s plan is to make wholesale sales when market prices allow for the economic operation of its generation facilities that are not being utilized to meet its retail demand.

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

	Three months ended
	March 31,
$ in millions	2015 vs. 2014
Retail
Rate	$	4.1
Volume		(6.5	)
Other miscellaneous		(5.0	)
Total retail change		(7.4	)
Wholesale
Rate		30.5
Volume		(13.5	)
Total wholesale change		17.0
RTO capacity & other
RTO capacity and other revenues		19.6
Total revenues change	$	29.2

For the three months ended March 31, 2015, Revenues increased $29.2 million to $461.3 million from $432.1 million in the same period in the prior year. The changes in the components of revenue are discussed below:

· Retail revenues decreased $7.4 million as a result of decreased volume due to a 4% decrease in heating degree days compared to 2014 and also due to customer switching. Also contributing to the decrease is lower retail revenue for SSO customers as the competitive auction rate, which represents 60% of our SSO load in 2015 compared to 10% in 2014, is lower than our non-auction generation rate. Partially offsetting these decreases are increased DP&L retail revenue due to recovery of previously deferred costs.

· Wholesale revenues increased $17.0 million as a result of a $30.5 million increase in wholesale prices partially offset by a $13.5 million volume variance. The year over year price increase is resulting from the impact of realized derivative losses in 2014 largely due to extreme weather during January of 2014. The volume decrease was driven by decreased intercompany sales to DPLER and a 21% decrease in net generation from DP&L’s co-owned and operated plants primarily due to the 2014 sale of East Bend and the closing of Beckjord as well as increased outages, partially offset by increased sales resulting from 60% of SSO load being served through the competitive bid process compared to 10% during 2014 allowing excess generation to be sold in the wholesale market.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $19.6 million compared to the same period in 2014. This increase was primarily the result of a $25.2 million increase in revenues realized from the PJM capacity auction offset by a $5.7 million decrease in RTO transmission and congestion revenue, as 2014 congestion revenue charges were higher due to extreme weather. The capacity prices that became effective in June 2014 were $126/MWh, compared to $28/MWh in June 2013.

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DP&L – Cost of Revenues

For the three months ended March 31, 2015:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $15.0 million, or 18%, compared to the same period in 2014, primarily due to a 21% decrease in internal generation at our plants partially offset by a 5% increase in average fuel cost per MWh.

Net purchased power increased $21.7 million, or 13%, compared to the same period in 2014 due largely to a $24.0 million volume increase driven by increased power purchased to source our SSO load through the competitive bid process as well as decreased internal generation and increased RTO capacity charges of $22.9 million. These increases were partially offset by an $18.1 million decrease in other RTO charges, a $3.3 million decrease due to lower average prices compared to 2014 and a $3.8 million decrease in net MTM losses. RTO capacity prices are set by an annual auction. The capacity prices that became effective in June 2014 were $126/MWh, compared to $28/MWh in June 2013. RTO charges are incurred as a member of PJM and include costs associated with our load obligations for retail customers. We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.

DP&L – Operation and Maintenance

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

	Three months ended
	March 31,
$ in millions	2015 vs. 2014
Low-income payment program (a)	$	(6.1	)
Generating facilities operations and maintenance expense		(2.8	)
Alternative energy and energy efficiency programs (a)		(2.2	)
Other, net		(0.4	)
Total change in operation and maintenance expense	$	(11.5	)

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

For the three months ended March 31, 2015, Operation and maintenance expense decreased $11.5 million, compared to the same period in the prior year. This variance was primarily the result of:

· decreased expenses for the low-income payment program which is funded by the USF revenue rate rider,

· decreased expenses relating to alternative energy and energy efficiency programs, and

· decreased maintenance expenses at our generating facilities.

DP&L – Depreciation and Amortization

For the three months ended March 31, 2015, Depreciation and amortization expense decreased $1.8 million compared to the same period in the prior year as a result of an adjustment of $0.6 million in the AROs for the Hutchings plant in 2015 compared to $1.2 million in 2014 and reductions in the depreciation expense due to the sale of the East Bend plant in December 2014 and the closure of the Beckjord plant in 2014, partially offset by routine plant additions and replacements.

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DP&L – General Taxes

For the three months ended March 31, 2015, General taxes decreased $3.4 million compared to the same period in the prior year. The decrease was primarily due to a 2014 adjustment to the 2013 estimated property tax liability to adjust estimates to actual payments made in 2014 partially offset by higher property tax accruals for 2015 compared to 2014.

DP&L – Interest Expense

Interest expense recorded during the three months ended March 31, 2015 increased $0.9 million compared to the same period in the prior year due to the timing of accruals and recoveries of carrying charges on DP&L’s regulatory riders. Accruals of carrying charges are recorded as a credit to interest expense, while recoveries are recorded as an increase to interest expense.

DP&L – Income Tax Expense

For the three months ended March 31, 2015, Income tax expense increased $10.8 million compared to the same period in 2014, primarily due to higher pre-tax income in 2015.

Financial Condition, Liquidity and Capital Requirements

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

	DPL
	Three Months ended March 31,						Years ended December 31,
	2015			2014			2014			2013			2012
	$ in millions
Net cash from operating activities	$	65.9		$	12.9		$	244.1		$	302.8		$	291.5
Net cash from investing activities		(34.4	)		(45.3	)		(112.6	)		(123.9	)		(199.2	)
Net cash from financing activities		-			-			(167.7	)		(317.8	)		(73.7	)
Net change		31.5			(32.4	)		(36.2	)		(138.9	)		18.6
Cash and cash equivalents at beginning of period		17.0			53.2			53.2			192.1			173.5
Cash and cash equivalents at end of period	$	48.5		$	20.8		$	17.0		$	53.2		$	192.1

The significant items that have impacted the cash flows for DPL for the years ended December 31, 2014, 2013 and 2012 are discussed in greater detail below:

DPL - Net Cash provided by Operating Activities

During the year ended December 31, 2014, Net cash provided by operating activities was primarily a result of Net loss adjusted for the noncash impacts of depreciation and amortization, the impairment of goodwill and fixed-assets, deferred income taxes, and a charge for the early redemption of debt.

During the year ended December 31, 2013, Net cash provided by operating activities was primarily a result of Net loss adjusted for the noncash impacts of depreciation and amortization, the impairment of goodwill and fixed-assets and deferred income taxes.

During the year ended December 31, 2012, Net cash provided by operating activities was primarily a result of Net income adjusted for noncash depreciation and amortization, as well as a noncash charge for the impairment of goodwill.

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DPL - Net Cash used for Investing Activities

During the year ended December 31, 2014, DPL’s cash used for investing activities was primarily related to capital expenditures, partially offset by proceeds from the sale of property.

During the year ended December 31, 2013, DPL’s cash used for investing activities was primarily related to capital expenditures.

During the year ended December 31, 2012, DPL’s cash used for investing activities was primarily related to capital expenditures.

DPL - Net Cash used for Financing Activities

During the year ended December 31, 2014, DPL’s Net cash used for financing activities primarily relates to the redemption of $335.0 million of debt and associated redemption premiums, partially offset by a $200.0 million issuance of new debt.

During the year ended December 31, 2013, DPL’s Net cash used for financing activities primarily relates to the payment at maturity of $470.0 million of DP&L’s senior secured bonds, early redemption of $475.1 million of debt and debt issuance costs, partially offset by the issuance of $445.0 million of new senior secured bonds, the issuance of $200.0 million of new debt.

During the year ended December 31, 2012, DPL’s Net cash used for financing activities primarily relates to common stock and payments to former warrant holders.

The significant items that have impacted the cash flows for DPL for the three months ended March 31, 2015 and 2014 are discussed in greater detail below:

Net cash from operating activities

The revenue from our utility business continues to be the principal source of cash from operating activities while our primary uses of cash include payments for fuel, purchased power, operation and maintenance expenses, interest and taxes. For the three months ended March 31, 2015, there was net cash from operating activities of $65.9 million.  This was a $53.0 million increase compared to the net cash from operating activities for the three months ended March 31, 2014 and was primarily driven by higher net income adjusted for depreciation and amortization and the impact of deferred income tax year over year.

Net cash from investing activities

During the three months ended March 31, 2015 and 2014, Net cash used for investing activities was primarily for capital expenditures at our generation plants.

Net cash from financing activities

During the three months ended March 31, 2015, DP&L borrowed and repaid $15.0 million from its revolving credit facilities. In addition, DP&L paid dividends on its preferred stock and common stock to parent.

Liquidity

We expect our existing sources of liquidity to remain sufficient to meet our anticipated operating needs. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to energy hedges, taxes and dividend payments. For 2015 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from debt financing as our internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under bank credit facilities will continue to be available to manage working capital requirements during those periods.

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As of March 31, 2015, DPL and DP&L have access to the following revolving credit facilities:

	Type	Maturity	Commitment		Amounts available as of March 31, 2015
	$ in millions
DPL	Revolving	May 2018	$	100.0	$	97.7
DP&L	Revolving	May 2018		300.0		298.6
			$	400.0	$	396.3

DPL’s revolving credit facility was established in May 2013. This facility expires in May 2018; however, if DPL has not refinanced its senior unsecured bonds due October 2016 before July 15, 2016, then this credit facility shall expire in July 2016. This facility has nine participating banks with no bank having more than 20% of the total commitment. DPL’s revolving credit facility has a $100.0 million letter of credit sublimit and a feature which provides DPL the ability to increase the size of the facility by an additional $50.0 million. As of March 31, 2015, there was one letter of credit issued in the amount of $2.3 million with the remaining $97.7 million available to DPL.

DP&L’s revolving credit facility, established in May 2013, expires in May 2018 and has nine participating banks, with no bank having more than 22.5% of the total commitment. This revolving credit facility has a $100.0 million letter of credit sublimit and DP&L also has the option to increase the potential borrowing amount under this facility by $100.0 million. At December 31, 2014, there were two letters of credit in the aggregate amount of $0.7 million outstanding, with the remaining $299.3 million available to DP&L. At March 31, 2015, there were two letters of credit in the amount of $1.4 million outstanding with the remaining $298.6 million available to DP&L.

Cash and cash equivalents for DPL amounted to $17.0 million at December 31, 2014 and $48.5 million at March 31, 2015. At that date, DPL did not have any short-term investments.

Capital Requirements

Construction Additions

	Actual						Projected
	2012		2013		2014		2015		2016		2017
	$ in millions
DPL	$	180	$	114	$	116	$	133	$	140	$	164

Planned construction additions for 2015 relate primarily to new investments in and upgrades to DP&L’s electric generating station equipment and transmission and distribution system. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental standards, among other factors. As discussed previously, DP&L must separate its generation assets by January 1, 2017. Accordingly, estimated capital expenditures related to the generation assets of $44.0 million are included in the DPL amounts.

DPL, primarily through its subsidiary DP&L, is projecting to spend an estimated $437.0 million in capital projects for the period 2015 through 2017 of which $378.0 million is projected to be spent by DP&L. DP&L is subject to the mandatory reliability standards of NERC and Reliability First Corporation (RFC), one of the eight NERC regions, of which DP&L is a member. NERC has recently changed the definition of the Bulk Electric System (BES) to include 100 kV and above facilities, thus expanding the facilities to which the reliability standards apply. DP&L’s 138 kV facilities were previously not subject to these reliability standards. Accordingly, DP&L anticipates spending approximately $67.0 million within the next five years to reinforce its 138 kV system to comply with these new NERC standards. Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds and the reasonable cost of external funds. We expect to finance our construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.

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Debt Covenants

The DPL revolving credit facility and the DPL term loan agreement that were put in place in May 2013 have two financial covenants. The first is a Total Debt to EBITDA ratio that will be calculated, at the end of each fiscal quarter, by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The ratio is not to exceed 8.50 to 1.00 for the fiscal quarters ending June 30, 2013 through December 31, 2014; it then steps down to not exceed 8.00 to 1.00 for the fiscal quarters ending March 31, 2015 through December 31, 2016; and it then steps down not to exceed 7.50 to 1.00 for the fiscal quarter ending March 31, 2017 through March 31, 2018. As of March 31, 2015, the financial covenant was met with a ratio of 5.21 to 1.00.

The second financial covenant is an EBITDA to Interest Expense ratio. The ratio is calculated, at the end of each fiscal quarter, by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. The ratio is not to be less than 2.00 to 1.00 for the fiscal quarter ending June 30, 2013 through December 31, 2014; it then steps up to not to be less than 2.10 to 1.00 for the fiscal quarter ending March 31, 2015 through December 31, 2016; and it then steps up to not to be less than 2.25 to 1.00 for the fiscal quarter ending March 31, 2017 through March 31, 2018. As of March 31, 2015, the financial covenant was met with a ratio of 3.45 to 1.00.

Both DPL’s unsecured revolving credit agreement and unsecured term loan restrict dividend payments from DPL to AES and adjust the cost of borrowing under the facilities under certain rating scenarios.

DP&L’s revolving credit facility that was put in place in May 2013 has two financial covenants. The first requires the Total Debt to Total Capitalization ratio to not exceed 0.65 to 1.00. As of December 31, 2014, this covenant was met with a ratio of 0.45 to 1.00. The above ratio is calculated as the sum of DP&L’s current and long-term portion of debt, including its guarantee obligations, divided by the total of DP&L’s shareholder’s equity and total debt including guarantee obligations. The second covenant, the EBITDA to Interest Expense ratio, is calculated at the end of each fiscal quarter, by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. DP&L’s EBITDA to Interest Expense ratio cannot be less than 2.50 to 1.00. As of March 31, 2015, this covenant was met with a ratio of 11.30 to 1.00.

Debt Ratings

During 2014, Moody’s downgraded DPL and DP&L’s credit and debt ratings. Standard & Poor’s and Fitch’s ratings did not change.

The following table outlines the debt ratings and outlook for DPL, along with the effective dates of each rating.

		Outlook	Effective
Fitch Ratings	BB	Stable	September 2014
Moody’s Investors Service, Inc.	Ba3	Stable	September 2014
Standard & Poor’s Financial Services LLC	BB	Stable	May 2014

Credit Ratings

The following table outlines the credit ratings (issuer/corporate rating) and outlook for DPL, along with the effective dates of each rating and outlook.

		Outlook	Effective
Fitch Ratings	B+	Stable	September 2014
Moody’s Investors Service, Inc.	Ba3	Stable	September 2014
Standard & Poor’s Financial Services LLC	BB	Stable	May 2014

On September 19, 2014, Moody s downgraded DPL’s senior unsecured debt rating from Ba2 Stable to Ba3 Stable, and DP&L’s senior unsecured credit rating from Baa2 Stable to Baa3 Stable. Moody’s also downgraded DP&L’s senior secured debt rating from Baa1 Stable to Baa2 Stable.

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If the rating agencies were to reduce our debt or credit ratings further, our borrowing costs may increase, our potential pool of investors and funding resources may be reduced, and we may be required to post additional collateral under selected contracts. These events may have an adverse effect on our results of operations, financial condition and cash flows. In addition, any such reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities. Non-investment grade companies, such as DPL, may experience higher costs to issue new securities. DP&L is still considered investment grade by one of the three rating agencies above.

Off-Balance Sheet Arrangements

DPL Guarantees

For information on guarantees, commercial commitments, and contractual obligations, see Note 9 of Notes to DPL’s consolidated financial statements as of December 31, 2015 and Note 9 of Notes to DPL’s condensed consolidated financial statements as of March 31, 2015.

Commercial Commitments and Contractual Obligations

We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2014, these include:

	Payments due in:
	Total		Less than 1 year		2 - 3 years		4 - 5 years		More than 5 years
	$ in millions
Long-term debt	$	2,163.2	$	20.1	$	655.2	$	260.2	$	1,227.7
Interest payments		847.7		107.8		196.0		175.0		368.9
Pension and postretirement payments		280.2		26.6		54.3		56.1		143.2
Operating leases		0.6		0.4		0.2		–		–
Coal contracts(1)		486.2		255.6		161.2		69.4		–
Limestone contracts(1)		18.3		6.1		12.2		–		–
Purchase orders and other contractual obligations		72.4		39.2		17.3		15.9		–
Total contractual obligations	$	3,868.6	$	455.8	$	1,096.4	$	576.6	$	1,739.8

(1) Total at DP&L operated units.

Long-term debt:

DPL’s Long-term debt as of December 31, 2014 consists of DPL’s unsecured notes and unsecured term loan, along with DP&L’s first mortgage bonds, tax-exempt pollution control bonds and the Wright-Patterson Air Force Base (WPAFB) note. These long-term debt amounts include current maturities but exclude unamortized debt discounts, premiums and fair value adjustments.

See Note 6 of the notes to DPL’s consolidated financial statements.

Interest payments:

Interest payments are associated with the long-term debt described above. The interest payments relating to variable-rate debt are projected using the interest rate prevailing at December 31, 2014.

Pension and postretirement payments:

As of December 31, 2014, DPL, through its principal subsidiary DP&L, had estimated future benefit payments as outlined in Note 8 of notes to DPL’s consolidated financial statements. These estimated future benefit payments are projected through 2024.

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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. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.

Limestone contracts:

DPL, through its principal subsidiary DP&L, has entered into various limestone contracts to supply limestone used in the operation of FGD equipment at its generating facilities.

Purchase orders and other contractual obligations:

As of December 31, 2014, DPL and DP&L had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.

Reserve for uncertain tax positions:

Due to the uncertainty regarding the timing of future cash outflows associated with our unrecognized tax benefits of $3.0 million at December 31, 2014, we are unable to make a reliable estimate of the periods of cash settlement with the respective tax authorities and have not included such amounts in the contractual obligations table above.

Market Risk

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

Commodity Pricing Risk

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

The coal market has increasingly been influenced by both international and domestic supply and consumption, making the price of coal more volatile than in the past, and while we have substantially all of the total expected coal volume needed to meet our retail and wholesale sales requirements for 2015 under contract, sales requirements may change, particularly for retail load. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments and some are priced based on market indices. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled outages and electric generation station mix. To the extent we are not able to hedge against price volatility or recover increases through our fuel and purchased power recovery rider that began in January 2010, our results of operations, financial condition or cash flows could be materially affected.

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In addition Dodd-Frank Act contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. We are considered an end-user under the Dodd-Frank Act and therefore are exempt from most of the collateral and margining requirements.  We are required to report our bilateral derivative contracts, unless our counterparty is a major swap participant or has elected to report on our behalf.  Even though we qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits or be unable to enter into certain transactions with us.

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

Commodity derivatives

To minimize the risk of fluctuations in the market price of commodities, such as coal, power, and heating oil, we may enter into commodity forward and futures contracts to effectively hedge the cost/revenues of the commodity. Maturity dates of the contracts are scheduled to coincide with market purchases/sales of the commodity. Cash proceeds or payments between us and the counterparty at maturity of the contracts are recognized as an adjustment to the cost of the commodity purchased or sold. We generally do not enter into forward contracts beyond thirty-six months. As of December 31, 2014, there are no coal derivatives.

A 10% increase or decrease in the market price of our heating oil forwards at December 31, 2014 would not have a significant effect on Net income.

The following table provides information regarding the volume and average market price of our power forward derivative contracts at December 31, 2014 and the effect to Net income if the market price were to increase or decrease by 10%:

Power Forwards	Contract Volume (in millions of MWh)			Weighted Average Market Price per MWh		Increase / decrease in Net income (in millions)
2015 - Net purchase/(Sale) position		0.2		$	41.06	$	0.3
2016 - Net purchase/(Sale) position		(1.2	)	$	40.31	$	(3.1	)
2017 - Net purchase/(Sale) position		–		$	–	$	–

A 10% increase or decrease in the market price of our heating oil forwards and FTRs at March 31, 2015 would not have a significant effect on Net income.

At March 31, 2015, a 10% increase or decrease in the market price of our forward power purchase contracts would result in an impact on unrealized gains/losses of $2.8 million, while a 10% increase or decrease in the market price of our forward power sale contracts would result in an impact on unrealized gains/losses of $12.6 million.

Wholesale revenues

Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins (DP&L’s electric revenues in the wholesale market include sales to DPLER).

Approximately 17% of DPL’s and 45% of DP&L’s electric revenues for the year ended December 31, 2014 were from sales of excess energy and capacity in the wholesale market.

Approximately 16% of DPL’s and 45% of DP&L’s electric revenues for the year ended December 31, 2013 were from sales of excess energy and capacity in the wholesale market.

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Approximately 11% of DPL’s and 36% of DP&L’s electric revenues for the year ended December 31, 2012 were from sales of excess energy and capacity in the wholesale market.

The table below provides the effect on annual Net income (net of an estimated income tax at 35%) as of December 31, 2014 of a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER), including the impact of a corresponding 10% change in the portion of purchased power used as part of the sale (note the share of the internal generation used to meet the DPLER wholesale sale would not be affected by the 10% change in wholesale prices):

	DPL
	$ in millions
Effect of 10% change in price per MWh	$	10.1

The following table presents the effect on annual Net income (net of estimated income taxes at 35%) as of March 31, 2015, of a hypothetical increase or decrease of 10% in the price per MWh of wholesale power (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER), including the impact of a corresponding 10% change in the portion of purchased power used as part of the sale (note that the share of the internal generation used to meet the DPLER wholesale sale would not be affected by the 10% change in wholesale prices):

	DPL
	$ in millions
Effect of 10% change in price per MWh	$	12.3

RPM Capacity revenues and costs

As a member of PJM, DP&L receives revenues from the RTO related to its transmission and generation assets and incurs costs associated with its load obligations for retail customers. PJM, which has a delivery year that runs from June 1 to May 31, has conducted auctions for capacity through the 2017/18 delivery year. The clearing prices for capacity during the PJM delivery periods from 2013/14 through 2017/18 are as follows:

	PJM Delivery Year
	2013/14		2014/15		2015/16		2016/17		2017/18
	($/MW-day)
Capacity clearing price	$	28	$	126	$	136	$	59	$	120

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

Future RPM auction results are dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion, and PJM s RPM business rules. The volatility in the RPM capacity auction pricing has had and will continue to have a significant impact on DPL’s capacity revenues and costs. Although DP&L currently has an approved RPM rider in place to recover or repay any excess capacity costs or revenues, the RPM rider only applies to customers supplied under our SSO. Customer switching reduces the number of customers supplied under our SSO, causing more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation.

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The table below provides estimates of the effect on annual Net income (net of an estimated income tax of 35%) as of December 31, 2014 of a hypothetical increase or decrease of $10/MW-day in the RPM auction price. The table shows the impact resulting from capacity revenue changes. We did not include the impact of a change in the RPM capacity costs since these costs will either be recovered through the RPM rider for SSO retail customers or recovered through the development of our overall energy pricing for customers who do not fall under the SSO. These estimates include the impact of the RPM rider and are based on the levels of customer switching experienced through December 31, 2014. As of December 31, 2014, approximately 29% of DP&L’s RPM capacity revenues and costs were recoverable from SSO retail customers through the RPM rider.

	DPL
	$ in millions
Effect of $10/MW-day change in capacity auction pricing	$	6.4

The following table provides estimates of the effect on annual Net income (net of estimated income taxes at 35%) as of March 31, 2015 of a hypothetical increase or decrease of $10/MW-day in the RPM auction price. The table shows the impact resulting from capacity revenue changes. We did not include the impact of a change in the RPM capacity costs since these costs will either be recovered through the RPM rider for SSO retail customers or recovered through the development of our overall energy pricing for customers who do not fall under the SSO.

	DPL
	$ in millions
Effect of $10/MW-day change in capacity auction pricing	$	6.4

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

There are proposals from PJM pending before the FERC that would modify capacity markets including near-term modifications with respect to RPM and longer-term modifications that would phase-out RPM and replace it with a Capacity Performance (“CP”) program. The final form of CP program has not been established and the effects on DP&L cannot be predicted. In concept, however, the CP program is intended to result in higher capacity prices paid to generators, paired with larger penalties for a generator s failure to perform during periods where electricity is in high demand. Future RPM or CP auction results will be dependent not only on the overall supply and demand of generation and load, but may also be affected by congestion as well as PJM’s business rules relating to bidding for demand response and energy efficiency resources in the capacity auctions.

Fuel and purchased power costs

DPL’s and DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the years ended December 31, 2014, 2013 and 2012 were 42%, 45% and 39%, respectively. We have a significant portion of projected 2015 fuel needs under contract. The majority of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We may purchase SO₂ allowances for 2015; however, the exact consumption of SO₂ allowances will depend on market prices for power, availability of our generation units and the actual sulfur content of the coal burned. We may purchase some NO_x allowances for 2015 depending on NO_x emissions. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and electric generation station mix.

Purchased power costs depend, in part, upon the timing and extent of planned and unplanned outages of our generating capacity as well as requirement to supply an increasing percentage of SSO load through the competitive bid auction. We will purchase power on a discretionary basis when wholesale market conditions provide opportunities to obtain power at a cost below our internal generation costs.

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Beginning January 1, 2010, DP&L was allowed to recover its fuel and purchased power costs associated with supplying SSO load as part of the fuel rider approved by the PUCO. Since there has been an increase in customer switching, SSO customers currently represent approximately 29% of DP&L’s total fuel costs. Beginning January 1, 2016, the fuel rider will no longer exist since SSO will at that time be supplied by 100% competitive bid.

The table below provides the effect on annual Net income (net of an estimated income tax at 35%) as of December 31, 2014, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate 29% recovery:

	DPL
	$ in millions
Effect of 10% change in fuel and purchased power	$	29.2

The following table provides the effect on annual Net income (net of estimated income taxes at 35%) as of March 31, 2015, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power:

	DPL
	$ in millions
Effect of 10% change in fuel and purchased power	$	36.6

Interest Rate Risk

As a result of our normal investing and borrowing activities, our financial results are exposed to fluctuations in interest rates, which we manage through our regular financing activities. We maintain both cash on deposit and investments in cash equivalents that may be affected by adverse interest rate fluctuations. DPL and DP&L have both fixed-rate and variable rate long-term debt. DPL’s variable-rate debt consists of a $160 million unsecured term loan with a syndicated bank group. The term loan interest rate fluctuates with changes in an underlying interest rate index, typically LIBOR. DP&L’s variable-rate debt is comprised of $100.0 million of publicly held pollution control bonds. The variable-rate bonds bear interest based on a prevailing rate that is reset weekly based on a comparable market index. Market indexes can be affected by market demand, supply, market interest rates and other economic conditions. See Note 6 of Notes to DPL’s consolidated financial statements and Note 4 of Notes to DPL’s condensed consolidated financial statements.

We partially hedged against interest rate fluctuations by entering into interest rate swap agreements to limit the interest rate exposure on the underlying financing. These interest rate swap agreements had mandatory settlement dates of September 30, 2013 and were being used to limit our exposure to changes in interest rates and the effect this could have on our future borrowing costs. On September 16, 2013 and immediately after the sale of DP&L’s new $445 million of First Mortgage Bonds, DP&L settled all of the above mentioned swap agreements at a total net settlement of $0. As of December 31, 2014, we do not have any interest rate hedging agreements still in place.

The carrying value of DPL’s debt was $2,159.7 million at December 31, 2014, consisting of DPL’s unsecured notes, unsecured term loan, Capital Trust II securities along with DP&L’s first mortgage bonds, tax-exempt pollution control bonds and the WPAFB note. All of DPL’s debt was adjusted to fair value at the Merger date according to FASC 805. The fair value of this debt at December 31, 2014 was $2,204.8 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DPL’s debt obligations that are sensitive to interest rate changes:

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Principal Payments and Interest Rate Detail by Contractual Maturity Date

	Principal payments due
	during the twelve months ending																		At March 31, 2015
	March 31,																		Principal		Fair
$ in millions	2016			2017			2018			2019			2020			Thereafter			Amount		Value
Variable-rate debt	$	30.0		$	40.0		$	40.0		$	50.0		$	-		$	100.0		$	260.0	$	260.0
Average interest rate (a)		2.4	%		2.4	%		2.4	%		2.4	%		-			0.1	%
Fixed-rate debt	$	0.1		$	575.1		$	0.1		$	0.2		$	200.2		$	1,127.5			1,903.2		1,978.5
Average interest rate		4.2	%		2.9	%		4.2	%		4.2	%		6.7	%		6.5	%
Total																			$	2,163.2	$	2,238.5

(a) Based on rates in effect at March 31, 2015

Long-term Debt Interest Rate Risk Sensitivity Analysis

Our estimate of market risk exposure is presented for our fixed-rate and variable-rate debt at March 31, 2015 for which an immediate adverse market movement causes a potential material effect on our financial condition, results of operations, or the fair value of the debt. We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. As of March 31, 2015, we did not hold any market risk sensitive instruments which were entered into for trading purposes.

Carrying value and fair value of debt with one percent interest rate risk

	At March 31, 2015				One percent
	Carrying		Fair		interest rate
$ in millions	Value (1)		Value		risk
Long-term debt
Variable-rate debt	$	260.0	$	260.0	$	2.6
Fixed-rate debt		1,899.7		1,978.5		19.8
Total	$	2,159.7	$	2,238.5	$	22.4

(1) Carrying value includes unamortized debt discounts and premiums.

DPL’s debt is comprised of both fixed-rate debt and variable-rate debt. In regard to fixed rate debt, the interest rate risk with respect to DPL’s long-term debt primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s $1,978.5 million of fixed-rate debt and not on DPL’s financial condition or results of operations. On the variable-rate debt, the interest rate risk with respect to DPL’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has

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on DPL’s results of operations related to the fair value of DPL’s $260.0 million variable-rate long-term debt outstanding as of March 31, 2015.

Equity Price Risk

As of December 31, 2014, approximately 18% of the defined benefit pension plan assets were comprised of investments in equity securities and 82% related to investments in fixed income securities, cash and cash equivalents, and alternative investments. The equity securities are carried at their market value of approximately $65.4 million at December 31, 2014. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6.5 million reduction in fair value as of December 31, 2014 and approximately a $0.3 million increase to the 2015 pension expense.

Credit Risk

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

Goodwill Impairments

During the first quarter of 2014, we performed an interim impairment test on the $135.8 million in goodwill at our DPLER reporting unit. The DPLER reporting unit was identified as being “at risk” during the fourth quarter of 2013. The impairment indicators arose based on market information available regarding actual and proposed sales of competitive retail marketers, which indicated a significant decline in valuations during the first quarter of 2014.

In Step 1 of the interim impairment test, the fair value of the reporting unit was determined to be less than its carrying amount under both the market approach and the income approach using a discounted cash flow valuation model. The significant assumptions included commodity price curves, estimated electricity to be demanded by its customers, changes in its customer base through attrition and expansion, discount rates, the assumed tax structure and the level of working capital required to run the business.

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.

In the fourth quarter of 2013, DPL completed its annual October 1 goodwill impairment tests and recognized goodwill impairment expense of $306.3 million. The Company identified both the DP&L and DPLER reporting units as at risk. A reporting unit is considered at risk when its fair value is not higher than its carrying amount by more than 10%. The Company monitors its reporting units at risk of step 1 failure on an ongoing basis. Since 2012, the DP&L reporting unit had been considered at risk subsequent to its goodwill impairments of $1,817.2 million recognized in 2012 and $306.3 million recognized in 2013. At December 31, 2014, goodwill at the DP&L reporting is not considered at risk. It is possible that we may incur goodwill impairment at the DP&L reporting unit in future periods if adverse changes in its business or operating environment occur. As of December 31, 2014 and March 31, 2015, the DP&L reporting unit had goodwill of $317.0 million and the DPLER reporting unit had no goodwill.

See Note 5 of notes to DPL’s consolidated financial statements for more information on the impairment of Goodwill.

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Critical Accounting Estimates

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

Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Historically, however, recorded estimates have not differed materially from actual results. Significant items subject to such judgments include: the carrying value of property, plant and equipment; the valuation of goodwill; 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.

Impairments

In accordance with the provisions of GAAP relating to the accounting for goodwill, goodwill is not amortized, but is evaluated for impairment 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. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions; operating or regulatory environment; increased competitive environment; increase in fuel costs particularly when we are unable to pass its effect to customers; negative or declining cash flows; loss of a key contract or customer particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods. See Note 5 of notes to DPL’s consolidated financial statements discussing the impairment of goodwill at DPL in 2014, 2013 and 2012.

In accordance with the provisions of GAAP relating to the accounting for impairments, long-lived assets to be held and used are reviewed for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used are recognized based on the fair value of the asset. We determine the fair value of these assets based upon estimates of future cash flows, market value of similar assets, if available, or independent appraisals, if required. In analyzing the fair value and recoverability using future cash flows, we make projections based on a number of assumptions and estimates of growth rates, future economic conditions, assignment of discount rates and estimates of terminal values. An impairment loss is recognized if the carrying amount of the long-lived asset is not recoverable from its undiscounted cash flows. The measurement of impairment loss is the difference between the carrying amount and fair value of the asset. See Note 15 of Notes to DPL’s consolidated financial statements discussing the impairment of long-lived assets in 2014 and 2013.

Revenue Recognition (including Unbilled Revenue)

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. The determination of the energy sales to customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. We recognize revenues 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

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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, projected line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class. Given our estimation method and the fact that customers are billed monthly, we believe it is unlikely that materially different results will occur in future periods when these amounts are subsequently billed.

Income Taxes

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since taxing authorities may interpret them differently. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to Net income and cash flows and adjustments to tax-related assets and liabilities could be material. We have adopted the provisions of GAAP relating to the accounting for uncertainty in income taxes. Taking into consideration the uncertainty and judgment involved in the determination and filing of income taxes, these GAAP provisions establish standards for recognition and measurement in financial statements of positions taken, or expected to be taken, by an entity on its income tax returns. Positions taken by an entity on its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information.

Deferred income tax assets and liabilities represent future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. We evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets.

Regulatory Assets and Liabilities

Application of the provisions of GAAP relating to regulatory accounting requires us to reflect the effect of rate regulation in DPL’s consolidated financial statements and DP&L’s Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, we defer these costs as Regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, we recognize Regulatory liabilities when it is probable that regulators will require customer refunds through future rates and when revenue is collected from customers for expenses that are not yet incurred. Regulatory assets are amortized into expense and Regulatory liabilities are amortized into income over the recovery period authorized by the regulator.

We evaluate our Regulatory assets to determine whether or not they are probable of recovery through future rates and make various assumptions in our analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period the assessment is made. We currently believe the recovery of our Regulatory assets is probable. See Note 3 of Notes to DPL’s consolidated financial statements.

AROs

In accordance with the provisions of GAAP relating to the accounting for AROs, legal obligations associated with the retirement of long-lived assets are required 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 allocated to expense over the useful life of the asset. These GAAP provisions also require that components of previously recorded depreciation related to the cost of removal of assets upon future retirement, whether legal AROs or not, must be removed from a company s accumulated depreciation reserve and be reclassified as a regulatory liability. We make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to AROs. These assumptions and estimates are based on historical experience and assumptions that we believe to be reasonable at the time.

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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 and may or may not be renewed at that time. Insurance and Claims Costs on DPL’s Consolidated Balance Sheets include estimated liabilities for insurance and claims costs of approximately $6.8 million and $6.4 million at March 31, 2015 and December 31, 2014, respectively. Furthermore, DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. In addition, DP&L has estimated liabilities for medical, life and disability claims costs below certain coverage thresholds of third-party providers. DPL and DP&L had recorded these additional insurance and claims liabilities of approximately $15.6 million and $18.8 million for 2014 and 2013, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for MVIC at DPL and the estimated liabilities for workers compensation, medical, life and disability claims at DP&L are actuarially determined using certain assumptions. There is uncertainty associated with the 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 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.

For 2015, we are decreasing our long-term rate of asset return assumption to 6.50% from 6.75% for pension plan assets. In addition, we are decreasing our long-term rate of asset return assumption to 4.50% from 6.00% for other postemployment benefit plan assets. These rates of return represent our long-term assumptions based on our current portfolio mixes and will impact the expense determination starting in 2015. Also, for 2015, we have decreased our assumed discount rate to 4.02% from 4.86% for pension and to 3.71% from 4.58% for postemployment benefits expense to reflect current duration-based yield curve discount rates.

A one percent change in the rate of return assumption for pension would result in an increase or decrease to the 2015 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 $0.5 million to 2015 pension expense. A 25 basis point decrease in the discount rate for pension would result in an increase of approximately $0.8 million to 2015 pension expense.

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. We provide postemployment health care benefits to employees who retired prior to 1987. A one percentage point change in the assumed health care cost trend rate would affect postemployment benefit costs by less than $1.0 million.

Contingent and Other Obligations

During the conduct of our business, we are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, insurance and other risks. We periodically evaluate our exposure to such risks and record estimated liabilities for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. In recording such estimated liabilities, we may make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to contingent and other obligations. These assumptions and estimates are based on historical experience and assumptions and may be subject to change. We, however, believe such estimates and assumptions are reasonable.

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Business

We are a diversified regional energy company that serves retail customers in West Central Ohio and Illinois through our subsidiaries, DP&L, which comprises our Utility segment, and DPLER, which comprises our Competitive Retail segment.

DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail services are still regulated. DP&L has the exclusive right to provide such services to its approximately 516,000 customers located in West Central Ohio. Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at five coal-fired power stations. Beginning in 2014, DP&L no longer provides 100% of the generation for its SSO customers. 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 prices of electricity and capacity. DP&L sells any excess energy and capacity into the wholesale market. DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER s retail customers.

DPLER sells competitive retail electric service, under contract, to residential, commercial, industrial and governmental customers. DPLER has approximately 143,000 customers currently located throughout Ohio. Approximately 124,000 of DPLER’s customers are also electric distribution customers of DP&L. DPLER does not have any transmission or generation assets and all of DPLER’s electric energy is purchased from DP&L to meet its sales obligations.

DPL’s other significant subsidiaries include: DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity and MVIC, DPL’s captive insurance company that provides insurance services to DP&L and DPL’s other subsidiaries. DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors. All of DPL’s subsidiaries are wholly-owned. DP&L does not have any subsidiaries.

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 recoveries in customer rates relate to expected future costs.

DPL and its subsidiaries had 1,185 employees as of March 31, 2015. At that date, 1,166 of these employees were employed by DP&L. Approximately 60% of the employees of DPL and its subsidiaries are under a collective bargaining agreement which expires on October 31, 2017.

In December 2013, an agreement was signed, effective January 1, 2014, whereby AES U.S. Services, LLC (the “Service Company”) began providing services including accounting, legal, human resources, information technology and other services of a similar nature on behalf of companies that are part of the AES U.S. Strategic Business Unit (“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 businesses served, including DP&L, are not subsidizing costs incurred for the benefit of non-regulated businesses.

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Electric Operations and Fuel Supply 

2014 Summer Generating Capacity   (in MW)
Summer Generating Capacity	Coal fired		Combustion Turbines, Diesel Units and Solar		Total
DPL		2,078		988		3,066

DPL’s present summer generating capacity, including peaking units, is 3,066 MW. Of this capacity, 2,078 MW, or 68%, is derived from coal-fired steam generating stations and the balance of 988 MW, or 32%, consists of combustion turbines, diesel peaking units and solar.

DP&L’s present summer generating capacity, including peaking units, is 2,510 MW. Of this capacity, 2,078 MW, or 83%, is derived from coal-fired steam generating stations and the balance of 432 MW, or 17%, consists of combustion turbines, diesel peaking units and solar.

Our all-time net peak load was 3,270 MW, occurring August 8, 2007.

100% of DP&L’s existing steam generating capacity is provided by generating units owned as tenants in common with Duke Energy and AEP Generation. As tenants in common, each company owns a specified share of each of these units, is entitled to its share of capacity and energy output and has a capital and operating cost responsibility proportionate to its ownership share. Additionally, DP&L, Duke Energy and AEP Generation own, as tenants in common, 880 circuit miles of 345,000-volt transmission lines. DP&L has several interconnections with other companies for the purchase, sale and interchange of electricity.

Duke Energy has entered into an agreement to sell its interest in the Killen, Stuart, Conesville Unit 4, Miami Fort 7 and 8 and Zimmer generating stations to various subsidiaries of Dynegy, Inc. This transaction was completed on April 2, 2015.

In 2014, we generated 99% of our electric output from coal-fired units and 1% from solar, oil and natural gas-fired units.

The following table sets forth DP&L’s and DPLE’s generating stations and, where indicated, those stations which DP&L owns as tenants in common:

				Approximate Summer MW Rating
Station	Ownership(1)	Operating Company	Location	DPL Portion(2)		Total
Coal Units(3)
Killen - Unit 2	C	DP&L	Wrightsville, OH		402		600
Stuart - Units 1 through 4	C	DP&L	Aberdeen, OH		808		2,308
Conesville - Unit 4	C	AEP Generation	Conesville, OH		129		780
Miami Fort - Units 7 & 8	C	Duke Energy	North Bend, OH		368		1,020
Zimmer - Unit 1	C	Duke Energy	Moscow, OH		371		1,320
Solar, Combustion Turbines or Diesel
Hutchings Unit 7	W	DP&L	Miamisburg, OH		25		25
Yankee Street Gas Turbine	W	DP&L	Centerville, OH		101		101
Yankee Solar	W	DP&L	Centerville, OH		1		1
Monument Diesels	W	DP&L	Dayton, OH		12		12
Tait Diesels	W	DP&L	Dayton, OH		10		10
Sidney Diesels	W	DP&L	Sidney, OH		12		12
Tait Units 1 – 3	W	DP&L	Moraine, OH		256		256
Killen Diesels	C	DP&L	Wrightsville, OH		12		18
Stuart Diesels	C	DP&L	Aberdeen, OH		3		10
Montpelier Units 1 – 4	W	DPLE	Poneto, IN		236		236
Tait Units 4 – 7	W	DPLE	Moraine, OH		320		320
Total approximate summer generating capacity					3,066		7,029

(1) W = Wholly-owned C = Commonly-owned

(2) DP&L portion of commonly-owned generating stations

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(3) Duke Energy has entered into an agreement to sell its interest in the Killen, Stuart, Conesville Unit 4, Miami Fort 7 and 8 and Zimmer generating stations to various subsidiaries of Dynegy, Inc. This transaction is currently waiting on regulatory approval.

In addition to the above, DP&L also owns a 4.9% equity ownership interest in OVEC, an electric generating company. OVEC has two electric generating stations located in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of 2,109 MW. DP&L’s share of this generation capacity is 103 MW.

On December 30, 2014, after receipt of all necessary regulatory approvals, DP&L sold its 31% ownership interest (186 MW) in East Bend Unit 2 to Duke Energy, Kentucky, Inc., which is the operator of the Unit and was the 69% owner. Beckjord Unit 6, in which DP&L had a 50% ownership interest, was retired effective October 1, 2014.

We have substantially all of the total expected coal volume needed to meet our retail and wholesale sales requirements for 2015 under contract. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments and some are priced based on market indices. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled/forced outages and generation station mix. Due to the installation of emission control equipment at certain commonly-owned units and barring any changes in the regulatory environment in which we operate, we expect to have balanced positions for SO₂, NO_x and renewable energy credits for 2015.

The gross average cost of fuel consumed per kWh was as follows:

	Average cost of Fuel Consumed
	2014		2013		2012
	(cents per kWh)
DPL		2.52		2.43		2.75

Seasonality

The power generation and delivery business is seasonal and weather patterns have a material effect on operating performance. In the region we serve, demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating compared to other times of the year. Unusually mild summers and winters could have an adverse effect on our results of operations, financial condition and cash flows.

Rate Regulation and Government Legislation

DP&L’s sales to SSO retail customers are subject to rate regulation by the PUCO. In addition, certain of DP&L’s recoverable costs are considered to be non-bypassable and are therefore assessed to all DP&L retail customers, under the regulatory authority of the PUCO, regardless of whom the customer selects to supply its retail electric service. DP&L’s transmission rates and wholesale electric rates to municipal corporations, rural electric co-operatives and other distributors of electric energy are subject to regulation by the FERC under the Federal Power Act.

Ohio law establishes the process for determining SSO and non-bypassable rates charged by public utilities. Regulation of retail rates encompasses the timing of applications, the effective date of rate increases, the market price of power, the cost basis upon which the rates are set and other related matters. Ohio law also established the Office of the OCC, which has the authority to represent residential consumers in state and federal judicial and administrative rate proceedings.

Ohio legislation extends the jurisdiction of the PUCO to the records and accounts of certain public utility holding company systems, including DPL. The legislation extends the PUCO’s supervisory powers to a holding company system’s general condition and capitalization, among other matters, to the extent that such matters relate to the costs associated with the provision of public utility service. Based on existing PUCO and FERC authorization, regulatory assets and liabilities are recorded on the balance sheets of both DPL and DP&L. See Note 3 of Notes to DPL’s Consolidated Financial Statements.

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Competition and Regulation

Ohio Matters

Ohio Retail Rates

The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.

Ohio law requires that all Ohio distribution utilities file either an ESP or MRO to establish rates for their SSO. According to Ohio law, under the MRO, a periodic competitive bid process will set the retail generation price after the utility demonstrates that it can meet certain market criteria and bid requirements. Also, under this option, utilities that still own generation in the state are required to phase-in the MRO over a period of not less than five years. An ESP may allow for adjustments to the SSO for costs associated with environmental compliance; fuel and purchased power; construction of new or investment in specified generating facilities; and the provision of standby and default service, operating, maintenance or other costs including taxes. As part of its ESP, a utility is permitted to file an infrastructure improvement plan that will specify the initiatives the utility will take to rebuild, upgrade or replace its electric distribution system, including cost recovery mechanisms. Both MRO and ESP options involve a SEET based on the earnings of comparable companies with similar business and financial risks.

On October 5, 2012, DP&L filed an ESP with the PUCO to establish SSO rates that were to be in effect starting January 2013. An order was issued by the PUCO on September 4, 2013 and a correction to that order was issued on September 6, 2013 (“ESP Order”).

After several rehearing requests, the ESP Order was revised several times. Collectively, the ESP orders state that DP&L’s current ESP began January 2014 and extends through May 31, 2017. The PUCO authorized DP&L to collect a non-bypassable Service Stability Rider (“SSR”) equal to $110 million per year from 2014 – 2016. The ESP Order also directed DP&L to divest its generation assets no later than January 1, 2017 and established DP&L’s SEET threshold at a 12% ROE. Beginning in 2014, DP&L is no longer permitted to supply 100% of the generation service for SSO customers. Instead, the PUCO directed DP&L to phase-in the competitive bidding structure with 10% of DP&L’s SSO load sourced through the competitive bid starting in 2014, 60% in 2015, and 100% by January 1, 2016. The ESP Order approved DP&L’s rate proposal to bifurcate its transmission charges into a non-bypassable component, TCRR-N, and a bypassable component, TCRR-B. The ESP order also required DP&L to establish a $2.0 million per year shareholder funded economic development fund.

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. Comments and reply comments were filed. DP&L amended its application on February 25, 2014 and again on May 23, 2014. Additional comments and reply comments were filed. On July 14, 2014, DP&L publicly announced its decision not to sell DP&L’s generation assets at this time, but to maintain its plans to transfer or sell the assets in accordance with PUCO orders by January 1, 2017. On September 17, 2014, the PUCO issued a Finding and Order in which it approved of DP&L’s plan to separate its generation assets with minor modifications.  Specifically, DP&L’s request to defer costs associated with OVEC which are not currently being recovered through existing rates was denied, and DP&L was ordered to transfer environmental liabilities with the generation assets.

Ohio law and the PUCO rules contain targets relating to renewable energy, demand reduction and energy efficiency standards. If any targets are not met, compliance penalties will apply unless the PUCO makes certain findings that would excuse performance. The PUCO has found that DP&L met its renewable targets for compliance years 2008 – 2013. PUCO staff recommended that DPLER met its targets for compliance year 2013. Both DP&L and DPLER are reported to be in full compliance with all renewable targets.

On June 13, 2014, Ohio Senate Bill 310 (“SB 310”) was signed into law, and it became effective September 12, 2014.  The new law changes several aspects to renewable energy and energy efficiency sections of law that were created in 2008 referred to as SB 221.  The new law freezes the renewable energy requirements at 2014 levels for 2015 and 2016 and the energy efficiency requirements if a utility modifies its portfolio plan.  The law also removes the advanced energy requirement and the renewable requirement of meeting half of

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the compliance level through facilities within the state.  DP&L did not file an amended portfolio plan, thereby extending its current plan through 2016.  DP&L recovers the costs of its compliance with Ohio energy efficiency and renewable energy standards through two separate riders.

The ESP Order also provided for the continuation of a fuel and purchased power recovery rider which began January 1, 2010. The fuel rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter: March 1, June 1, September 1 and December 1 each year. As part of the PUCO approval process, an outside auditor is hired each year to review fuel costs and the fuel procurement process. On June 12, 2013, we received a 2012 audit report recommending a pre-tax disallowance of $5.3 million of costs. In August 2014, the PUCO issued an order in that case that included the disallowance of an immaterial amount of fuel costs. The impact of the order issued was a reversal in the third quarter of a previously established $2.6 million reserve. The 2013 fuel audit report found only minor disallowances. The Company, the PUCO staff and OCC reached a stipulation resolving all issues in the 2013 audit. This Stipulation is pending PUCO approval.

As a member of PJM, DP&L receives revenues from the RTO related to DP&L’s transmission and generation assets and incurs costs associated with its load obligations for retail customers. Ohio law includes a provision that would allow Ohio electric utilities to seek and obtain a reconcilable rider to recover RTO-related costs and credits. DP&L’s TCRR and PJM RPM riders were initially approved in November 2009 to recover these costs. In accordance with the ESP Order, TCRR-N and TCRR-B began on January 1, 2014. Both the TCRR-B and the RPM riders assign costs and revenues from PJM monthly bills to retail ratepayers based on the percentage of SSO retail customers load and sales volumes to total retail load and total retail and wholesale volumes. Customer switching to CRES providers decreases DP&L’s SSO retail customers load and sales volumes. Therefore, increases in customer switching cause more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation. RPM capacity costs and revenues are discussed further under in “Risk Factors”. DP&L files an annual true-up of TCRR-N and both TCRR-B and RPM are trued up on a quarterly basis beginning January 2014 through January 1, 2016, at which point they will be eliminated as a result of the SSO load being supplied 100% through the competitive bid process.

For calendar year 2012, DP&L was subject to a SEET threshold in which DP&L was required to apply general rules for calculating the earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings. Pursuant to an Order issued on February 13, 2014, DP&L’s 2012 earnings were found to not be excessive. Through the ESP Order, the PUCO established DP&L’s ROE SEET threshold at 12% beginning with 2013. On May 15, 2014, DP&L filed its application to demonstrate that it did not have significantly excessive earnings for calendar year 2013. A stipulation was reached with the PUCO staff agreeing that DP&L did not exceed the SEET threshold for 2013, which was filed on July 22, 2014. At a hearing held on September 9, 2014 and on October 1, 2014, the PUCO issued an order approving the SEET Stipulation. In future years, the SEET could have a material effect on our results of operations, financial condition and cash flows.

Ohio Competitive Considerations and Proceedings

Since January 2001, DP&L’s electric customers have been permitted to choose their retail electric generation supplier. DP&L continues to have the exclusive right to provide delivery service in its state-certified territory and the obligation to supply and/or procure retail generation service to customers that do not choose an alternative supplier. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.

Market prices for power, as well as government aggregation initiatives, have led and may continue to lead to the entrance of additional competitors in our service territory. As of December 31, 2014, there were forty-three CRES providers registered in DP&L’s service territory. DPLER, an affiliated company and one of the forty-three registered CRES providers, has been marketing supply services to DP&L customers. During 2014, DPLER accounted for approximately 5,649 million kWh of the total 10,014 million kWh supplied by CRES providers within DP&L’s service territory. Also during 2014, 110,536 customers with an annual energy usage of 4,365 million kWh were supplied by other CRES providers within DP&L’s service territory. The volume supplied by DPLER represents approximately 40% of DP&L’s total distribution sales volume during 2014. We cannot determine the extent to which customer switching to CRES providers will occur in the future and the effect this will have on us. Because DPLE was one of the winning bidders in the competitive bid auction, and

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therefore provides generation service to a portion of the SSO load through May 2017, future additional customer switching away from SSO load will continue to have a negative financial impact on DPL, but to a lesser degree. Beginning January 1, 2016, 100% of SSO load will be served through the competitive bid auction. After that date, customer switching will have no impact on DP&L’s financial condition.

Several communities in DP&L’s service area have passed ordinances allowing the communities to become government aggregators for the purpose of offering retail generation service to their residents. To date, a number of communities have filed with the PUCO to initiate aggregation programs.  If a number of the larger communities in DP&L’s service area move forward with aggregation in 2015, it could have a material effect on our earnings. In 2014, the City of Dayton announced it decided to move forward with its plans to implement a government aggregation program. Depending on the timing of implementation of this program, it could have a significant financial impact on DPL. As discussed above, beginning January 1, 2016, customer switching will have no effect on DP&L’s net income.

DPLER began providing CRES services to business customers in Ohio who are not in DP&L’s service territory in 2010 and to residential customers in 2012. 

Federal Matters

Like other electric utilities and energy marketers, DP&L and DPLE may sell or purchase electric products in the wholesale market. DP&L and DPLE compete with other generators, power marketers, privately and municipally-owned electric utilities and rural electric cooperatives when selling electricity. The ability of DP&L and DPLE to sell this electricity will depend not only on the performance of our generating units, but also on how DP&L’s and DPLE s prices, terms and conditions compare to those of other suppliers.

As part of Ohio s electric deregulation law, all of the state’s investor-owned utilities were required to join an RTO. In October 2004, DP&L successfully integrated its high-voltage transmission lines into the PJM RTO. The role of the RTO is to administer a competitive wholesale market for electricity and ensure reliability of the transmission grid. PJM ensures the reliability of the high-voltage electric power system serving more than 50 million people in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM coordinates and directs the operation of the region s transmission grid, administers the world’s largest competitive wholesale electricity market and plans regional transmission expansion improvements to maintain grid reliability and relieve congestion.

The PJM RPM capacity base residual auction for the 2017/18 period cleared at a price of $120/MW-day for our RTO area.  The prices for the periods 2016/17, 2015/16 and 2014/15 were $59/MW-day, $136/MW-day and $126/MW-day, respectively, based on previous auctions. There are proposals from PJM pending before the FERC that would modify capacity markets including near-term modifications with respect to RPM and longer-term modifications that would phase-out RPM and replace it with a Capacity Performance program. The final form of CP program has not been established and the effects on DP&L cannot be predicted. In concept, however, the CP program is intended to result in higher capacity prices paid to generators, paired with larger penalties for a generator s failure to perform during periods where electricity is in high demand. Future RPM or CP auction results will be dependent not only on the overall supply and demand of generation and load, but may also be affected by congestion as well as PJM’s business rules relating to bidding for demand response and energy efficiency resources in the capacity auctions. Increases in customer switching causes more of the capacity costs and revenues to be excluded from the DP&L’s Ohio RPM rider calculation. We cannot predict the outcome of future auctions or customer switching but if the current auction price is not sustained or if higher penalties are incurred due to implementation of the CP program and DP&L’s generation performance, it could have a material adverse effect on our future results of operations, financial condition and cash flows.

NERC is a FERC-certified electric reliability organization responsible for developing and enforcing mandatory reliability standards, including Critical Infrastructure Protection (“CIP”) reliability standards, across eight reliability regions.  In December 2012, DP&L underwent routine, scheduled NERC audits conducted by Reliability First Corporation (RFC), which focused on our performance in supporting PJM as our transmission operator, and our compliance with the CIP standards. DP&L was found 100% compliant in its performance in support of PJM. In the CIP audit, four minor documentation-related Possible Alleged Violations (“PAVs”) were identified, which were settled through a streamlined process, without any financial penalties. In November

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2013, DPLE, DPL’s merchant generation affiliate, underwent a routine, scheduled NERC audit, during which one minor PAV was identified; DPL anticipates that it will be settled through a streamlined process, with no financial penalty.

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 $0.8 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, which are disclosed in the paragraphs below. 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. See Note 13, Contractual Obligations, Commercial Commitments and Contingencies Environmental Matters in DPL’s Consolidated Financial Statements for more information regarding environmental risks, laws and regulations and legal proceedings to which we are and may be subject to in the future.

Capital Expenditures for Environmental Matters

DP&L’s environmental capital expenditures were approximately $3.6 million, $2.0 million and $8.0 million in 2014, 2013 and 2012, respectively. DP&L has budgeted $10.7 million in environmental-related capital expenditures for 2015.

Legal and Other Matters

See Note 13 of notes to DPL’s consolidated financial statements for additional information about certain legal matters.

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Electric Sales and Revenues

The following table sets forth DPL’s electric sales and revenues for the years ended December 31, 2014, 2013 and 2012, respectively.

	DPL
	Year ended December 31, 2014		Year ended December 31, 2013		Year ended December 31, 2012
Electric sales (millions of kWh)		18,763		19,561		16,454
Billed electric customers (end of period)		644,483		692,670		637,708

DPL is structured in two operating segments, DP&L and DPLER. See Note 14 of Notes to DPL’s consolidated financial statements as of December 31, 2014and Note 10 of Notes to DPL’s condensed consolidated financial statements as of March 31, 2015 for more information on DPL’s segments.

The following tables set forth DP&L’s and DPLER s electric sales and revenues for the years ended December 31, 2014, 2013 and 2012, respectively.

	DP&L(1)
	Year ended December 31, 2014		Year ended December 31, 2013		Year ended December 31, 2012
Electric sales (millions of kWh)		18,613		19,423		15,606
Billed electric customers (end of period)		515,622		514,926		513,282

	DPLER(2)
	Year ended December 31, 2014		Year ended December 31, 2013		Year ended December 31, 2012
Electric sales (millions of kWh)		9,717		9,733		8,315
Billed electric customers (end of period)		260,097		308,047		198,098

(1) DP&L sold 5,649 million kWh, 5,874 million kWh and 6,201 million kWh of power to DPLER (a subsidiary of DPL) for the years ended December 31, 2014, 2013 and 2012, respectively.

(2) This chart includes all sales of DPLER, both within and outside of the DP&L service territory.

The following tables set forth DPL’s, DP&L’s and DPLER s electric sales and revenues for the three months ended March 31, 2015 and 2014, respectively.

	DPL				DP&L (a)				DPLER (b)
	Three months ended				Three months ended				Three months ended
	March 31,				March 31,				March 31,
	2015		2014		2015		2014		2015		2014
Electric Sales (millions of kWh)		5,082		5,375		4,971		5,314		2,048		2,782
Billed electric customers (end of period)		650,712		699,619		516,324		515,748		258,755		322,291

(a) This table contains electric sales from DP&L’s generation and purchased power. DP&L sold 1,149 million kWh and 1,604 million kWh of power to DPLER during the three months ended March 31, 2015 and 2014, respectively, not included above to avoid duplication.

(b) This chart includes all sales of DPLER and MC Squared, both within and outside of the DP&L service territory.

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Description of the Notes

In this Description of the Notes, “DPL” refers only to DPL Inc. and any successor obligor on the notes, and not to any of its subsidiaries, and references to the “Company,” “we,” “us,” and “our” refer to DPL. You can find the definitions of certain terms used in this description under “—Certain Definitions.”

We issued the notes in an aggregate principal amount of $200,000,000 under an indenture between us and U.S. Bank National Association, as trustee dated as of October 6, 2014. The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939 (the “Trust Indenture Act”).

The following is a summary of the material provisions of the indenture and the notes. Because this is a summary, it may not contain all the information that is important to you. You should read the indenture in its entirety because it, not this description, defines your rights as holders of the notes. Copies of the indenture are available as described under “Where You Can Find More Information,” and the indenture is filed as an exhibit to the registration statement of which this prospectus is part.

In exchange for the notes issued on October 6, 2014, we are issuing the new notes under the indenture for public resale pursuant to this prospectus. All references to notes below refer to the old notes and/or the new notes unless the context otherwise requires.

Basic Terms of Notes

The notes:

· are senior unsecured obligations of DPL;

· are effectively subordinated to any secured senior obligations of DPL, to the extent of the value of the collateral securing such obligations;

· rank equally with the existing and future unsubordinated and unsecured obligations of DPL;

· are structurally subordinated in right of payment to obligations of the subsidiaries of DPL;

· mature on October 1, 2019;

· are issued in an original aggregate principal amount of $200 million; and

· bear interest at 6.75% per annum, payable semiannually on each April 1 and October 1 to holders of record on the March 15 or September 15 immediately preceding the interest payment date. Interest on the notes accrues from the most recent date to which interest has been paid.

Interest will be computed on the basis of a 360-day year of twelve 30-day months.

At March 31, 2015, DPL’s direct and indirect subsidiaries had approximately $2,087.6 million of debt and other liabilities, including trade payables and preferred stock outstanding, all of which would be effectively senior to the notes.

At March 31, 2015, DPL had, on an unconsolidated basis, approximately $1,270.0 million of senior unsecured debt, no secured debt and no subordinated debt outstanding.

At March 31, 2015, DPL had, on a consolidated basis, approximately $1,303.8 million of senior unsecured debt, $859.4 million of secured debt and no subordinated debt outstanding.

Our ability to pay interest on the notes will be dependent upon the receipt of dividends and other distributions from our direct and indirect subsidiaries, including The Dayton Power and Light Company (“DP&L”) in particular. The availability of distributions from our subsidiaries is subject to the satisfaction of

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various covenants and conditions contained in the applicable subsidiaries’ existing and future financing and governance documents.

The indenture does not limit the amount of debt securities we may issue under the indenture and provides that debt securities may be issued from time to time in one or more series. We may from time to time, without notice to or the consent of the holders of the notes, create and issue additional debt securities (“Additional Notes”) under the indenture governing the notes having the same terms as, and ranking equally with, the notes in all respects (except for the offering price and issue date). Any Additional Notes, together with the notes offered hereby, will constitute a single series of notes under the indenture, and will be treated as a single class for all purposes thereunder, including voting under the indenture; provided that, if the Additional Notes are not fungible with the notes for U.S. federal income tax purposes, the Additional Notes will have a separate CUSIP number.

Optional Redemption

The notes will be redeemable at any time before September 1, 2019 in whole or from time to time in part, at our option at a redemption price equal to the greater of:

(1) 100% of the principal amount of the notes being redeemed; or

(2) the sum of the present values of the remaining scheduled payments of principal of and interest on the notes being redeemed discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined herein) plus 50.0 basis points;

plus, for (1) or (2) above, whichever is applicable, accrued interest on such notes to, but excluding, the date of redemption.

For purposes of the foregoing discussion of our right to redeem the notes, the following definitions are applicable:

“Comparable Treasury Issue” means the United States Treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term (as measured from the date of redemption) of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the notes.

“Comparable Treasury Price” means, with respect to any redemption date, (i) the average of five Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest such Reference Treasury Dealer Quotations, or (ii) if the Company obtains fewer than five such Reference Treasury Dealer Quotations, the average of all such quotations.

“Quotation Agent” means any Reference Treasury Dealer appointed by us.

“Reference Treasury Dealer” means (i) each of Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC (or their respective affiliates that are Primary Treasury Dealers) and their respective successors; provided, however, that if any of the foregoing shall cease to be a primary U.S. Government securities dealer in New York City (a “Primary Treasury Dealer”), we will substitute therefor another Primary Treasury Dealer, and (ii) any other Primary Treasury Dealers selected by us.

“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Quotation Agent, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Quotation Agent by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third business day preceding such redemption date.

“Treasury Rate” means, with respect to any redemption date, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury

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Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date.

The redemption price will be calculated by the Quotation Agent and we, the trustee and any paying agent for the notes to be redeemed will be entitled to rely on such calculation. It shall be the Company’s sole obligation to calculate the present value of the payments in connection with a redemption and the trustee shall have no obligation to calculate or verify any such payment amounts.

At any time on or after September 1, 2019, we may redeem the notes, in whole or in part, at 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest to, but excluding, the date of redemption.

Notice of redemption must be given not less than 30 days nor more than 60 days prior to the date of redemption. If fewer than all the notes are to be redeemed, selection of notes for redemption will be made by the trustee in any manner the trustee deems fair and appropriate.

Unless we default in payment of the redemption price from and after the redemption date, the notes or portions of them called for redemption will cease to bear interest, and the holders of the notes will have no right in respect to such notes except the right to receive the redemption price for them.

No Other Mandatory Redemption or Sinking Fund

There will be no mandatory redemption or sinking fund payments for the notes.

Repurchase at the Option of Holders

If a Change of Control Triggering Event (as defined herein) occurs, unless we have exercised our right to redeem the notes as described above, holders of all outstanding notes will have the right to require us to repurchase all or any part (no note of a principal amount of $2,000 or less will be repurchased in part) of their notes pursuant to the offer described below (the “Change of Control Offer”) on the terms set forth in the indenture. In the Change of Control Offer, we will be required to offer payment in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest, if any, on the notes repurchased, to, but excluding, the date of purchase (the “Change of Control Payment”). Within 30 days following any Change of Control Triggering Event, we will be required to send a notice to holders of notes describing the transaction or transactions that constitute the Change of Control Triggering Event and offering to repurchase the notes on the date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed (the “Change of Control Payment Date”), pursuant to the procedures required by the indenture and described in such notice. We must comply with the requirements of Rule 14e-1 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control Triggering Event. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the notes, we will be required to comply with the applicable securities laws and regulations and will not be deemed to have breached our obligations under the Change of Control provisions of the notes by virtue of such conflicts.

On the Change of Control Payment Date, we will be required, to the extent lawful, to:

· accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer;

· deposit with the paying agent, which shall initially be the trustee, an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

· deliver or cause to be delivered to the trustee the notes properly accepted.

The definition of Change of Control (defined herein) includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of us and our subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase

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“substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require us to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of us and our subsidiaries taken as a whole to another person may be uncertain.

For purposes of the foregoing discussion of a repurchase at the option of holders, the following definitions are applicable:

“Change of Control” means the occurrence of any of the following: (1) the direct or indirect sale, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Company and its subsidiaries taken as a whole to any person (as such term is used in Section 13(d) of the Exchange Act) other than the Company or one of its subsidiaries; (2) the consummation of any transaction (including, without limitation, any merger or consolidation), the result of which is that any person (as such term is used in Section 13(d) of the Exchange Act) other than a Permitted Holder (as defined herein) becomes the beneficial owner, directly or indirectly, of more than 50% of the then outstanding number of shares of the Company’s Voting Stock; or (3) the first day on which a majority of the members of the Company’s Board of Directors are not Continuing Directors of the Company.

“Change of Control Triggering Event” means the occurrence of a Rating Event and a Change of Control.

“Continuing Directors” means, as of any date of determination, any member of the applicable Board of Directors who (1) was a member of such Board of Directors on the date of the issuance of the notes; or (2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board of Directors at the time of such nomination or election (either by vote of the Board of Directors or by approval of the stockholders, or, if applicable, after receipt of a proxy statement in which such member was named as a nominee for election as a director, without objection to such nomination).

“Permitted Holder” means, at any time, The AES Corporation (“AES”) and its Affiliates. In addition, any person or group whose acquisition of beneficial ownership constitutes a Change of Control in respect of which a Change of Control Offer is made in accordance with the requirements of the indenture will thereafter, together with its Affiliates, constitute an additional Permitted Holder.

“Rating Agencies” means (a) each of Fitch, Moody’s and S&P and (b) if any of Fitch, Moody’s or S&P ceases to rate the notes or fails to make a rating of the notes publicly available for reasons outside of our control, a “nationally recognized statistical rating organization”(within the meaning of Section 3(a)(62) of the Exchange Act) selected by us as a replacement Rating Agency for a former Rating Agency.

“Rating Event” means the rating on the notes is lowered by two of the three Rating Agencies on any day within the period commencing on the earlier of (a) the occurrence of a Change of Control and (b) public notice of the occurrence of a Change of Control or our intention to effect a Change of Control and ending 60 days following the consummation of such Change of Control (which 60-day period will be extended so long as the rating of the notes is under publicly announced consideration for a possible downgrade by any of the Rating Agencies).

“Voting Stock” of any specified person means the capital stock of such person that is at the time entitled to vote generally in the election of the Board of Directors of such person.

It shall be the Company’s sole obligation to determine if a Rating Event has occurred and the trustee shall have no obligation to determine or verify if such an event has occurred.

Ranking

Structural Subordination. DPL is a holding company. Substantially all of DPL’s operations are conducted through its subsidiaries. Claims of creditors of DPL’s subsidiaries, including trade creditors, secured creditors and creditors holding debt and guarantees issued by those subsidiaries, and claims of preferred and minority stockholders (if any) of those subsidiaries generally will have priority with respect to the assets and earnings of

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those subsidiaries over the claims of creditors of DPL, including holders of the notes. The notes will be effectively subordinated in right of payment to creditors (including trade creditors) and preferred and minority stockholders (if any) of DPL’s subsidiaries.

At March 31, 2015, DPL’s direct and indirect subsidiaries had approximately $2,087.69.5 million of debt and other liabilities, including trade payables and preferred stock outstanding, all of which would be effectively senior to the notes. Moreover, the indenture does not impose any limitation on the incurrence of additional liabilities or the issuance of additional preferred stock or minority interests by subsidiaries of DPL (subject to compliance with the Limitation on Liens covenant in the case of secured debt).

The notes are senior unsecured obligations of DPL and are effectively subordinated to any secured senior obligations of DPL, to the extent of the value of the collateral securing such obligations. The notes rank equally in right of payment with the existing and future unsubordinated and unsecured obligations of DPL and are structurally subordinated to obligations of the subsidiaries of DPL.

Moreover, as a holding company, DPL owns assets primarily through its ownership interests in its subsidiaries. None of its subsidiaries is obligated under the notes and none of its subsidiaries will guarantee the notes. DPL’s principal asset is its ownership interest in DP&L. DP&L is a regulated public utility, and is subject to regulation at both the state and federal level. At the state level, it is subject to regulation by the PUCO. At the federal level, it is subject to regulation by FERC. See “Business—Rate Regulation and Government Legislation” and “Business—Competition and Regulation” appearing elsewhere in this prospectus. Regulation by the PUCO and FERC includes regulation with respect to the change of control and transfer or ownership of utility property. Accordingly, if the trustee under the indenture or the holders of the notes institute proceedings against us with respect to the notes, the remedies available to them may be limited and may be subject to the approval by the PUCO and FERC.

Open Market Purchases

DPL may at any time purchase notes in the open market or otherwise at any price. Any such purchased notes will not be resold, except in compliance with applicable requirements or exemptions under the relevant securities laws.

Covenants

Except as otherwise set forth under “—Defeasance and Discharge” below, for so long as any notes remain outstanding or any amount remains unpaid on any of the notes, we will comply with the terms of the covenants set forth below.

Payment of Principal and Interest

We will duly and punctually pay the principal of and interest on the notes in accordance with the terms of the notes and the indenture.

Merger, Consolidation, Sale, Lease or Conveyance

The indenture provides that we will not (i)(a) consolidate with or merge with or into any other person, or permit any person to merge into or consolidate with us, or convey, transfer or lease our consolidated properties and assets substantially as an entirety (in one transaction or in a series of related transactions), (b) convey, transfer or lease our consolidated electric transmission and distribution assets and operations substantially as an entirety (in one transaction or in a series of related transactions), or (c) convey, transfer or lease all or substantially all of our consolidated electric generation assets and operations (in one transaction or a series of transactions), to any person or (ii) permit any of our subsidiaries to enter into any such transaction or series of transactions if it would result in the disposition of (x) our consolidated properties and assets substantially as an entirety, (y) our consolidated electric transmission and distribution assets and operations substantially as an entirety or (z) all or substantially all of our consolidated electric generation assets and operations unless, in each case:

· we will be the surviving entity; or

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· the successor corporation or person that acquires all or substantially all of our assets:

· will be an entity organized under the laws of the United States of America, one of its States or the District of Columbia; and

· expressly assumes by supplemental indenture our obligations under the notes and the indenture, provided, however, that in the event following a conveyance, transfer or lease of our consolidated properties and assets substantially as an entirety or a conveyance, transfer or lease of all or substantially all of our consolidated electric generation assets and operations, we continue to own, directly or indirectly, our consolidated electric transmission and distribution assets and operations that we held immediately preceding such conveyance, transfer or lease substantially as an entirety, the notes and the indenture shall remain the obligations of us and shall not be assumed by the surviving person;

in each case, immediately after the merger, consolidation, sale, lease or conveyance, we, that person or the surviving entity will not be in default under the indenture.

In addition to the indenture limitations, regulatory approval would be required for such transactions.

Limitations on Liens

Neither we nor any Significant Subsidiary (as defined herein) may issue, assume or guarantee any Indebtedness secured by a Lien upon any property or assets (other than any cash or cash equivalents) of us or such Significant Subsidiary (including, for the avoidance of doubt, any common stock of DP&L), as applicable, without effectively providing that the outstanding notes (together with, if we so determine, any other indebtedness or obligation then existing or thereafter created ranking equally with the notes) will be secured equally and ratably with (or prior to) such Indebtedness so long as such Indebtedness is so secured.

The foregoing limitation on Liens will not, however, apply to:

(1)    Liens in existence on the date of original issue of the notes;

(2)    any Lien created or arising over any property which is acquired, constructed or created by us or any of our Significant Subsidiaries, but only if:

(a)    such Lien secures only principal amounts (not exceeding the cost of such acquisition, construction or creation) raised for the purposes of such acquisition, construction or creation, together with any costs, expenses, interest and fees incurred in relation to that property or a guarantee given in respect of that property;

(b)    such Lien is created or arises on or before 180 days after the completion of such acquisition, construction or creation; and

(c)    such Lien is confined solely to the property so acquired, constructed or created;

(3)   (a)     rights of financial institutions to offset credit balances in connection with the operation of cash management programs established for our benefit and/or a Significant Subsidiary or in connection with the issuance of letters of credit for our benefit and/or a Significant Subsidiary;

(b)    any Lien on accounts receivable securing our Indebtedness and/or a Significant Subsidiary incurred in connection with the financing of such accounts receivable;

(c)    any Lien incurred or deposits made in the ordinary course of business, including, but not limited to, (1) any mechanic’s, materialmen’s, carrier’s, workmen’s, vendors’ and other like Liens and (2) any Liens securing amounts in connection with workers’ compensation, unemployment insurance and other types of social security;

(d)    any Lien upon specific items of inventory or other goods of us and/or a Significant Subsidiary and the proceeds thereof securing obligations of us and/or a Significant Subsidiary in

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respect of bankers’ acceptances issued or created for the account of such person to facilitate the purchase, shipment or storage of such inventory or other goods;

(e)    any Lien incurred or deposits made securing the performance of tenders, bids, leases, trade contracts (other than for borrowed money), statutory obligations, surety bonds, appeal bonds, government contracts, performance bonds, return-of-money bonds, letters of credit not securing borrowings and other obligations of like nature incurred in the ordinary course of business;

(f)    any Lien created by us or a Significant Subsidiary under or in connection with or arising out of a Currency, Interest Rate or Commodity Agreement (as defined herein) or any transactions or arrangements entered into in connection with the hedging or management of risks relating to the electricity or natural gas distribution industry, including a right of set off or right over a margin call account or any form of cash or cash collateral or any similar arrangement for obligations incurred in respect of Currency, Interest Rate or Commodity Agreements;

(g)    any Lien arising out of title retention or like provisions in connection with the purchase of goods and equipment in the ordinary course of business; and

(h)    any Lien securing reimbursement obligations under letters of credit, guaranties and other forms of credit enhancement given in connection with the purchase of goods and equipment in the ordinary course of business;

(4)    Liens in favor of us or a subsidiary of ours;

(5)   (a)    Liens on any property or assets acquired from an entity which is merged with or into us or a Significant Subsidiary or any Liens on the property or assets of any entity existing at the time such entity becomes a subsidiary of ours and, in either case, is not created in anticipation of the transaction, unless the Lien was created to secure or provide for the payment of any part of the purchase price of that entity;

(b)    any Lien on any property or assets existing at the time of its acquisition and which is not created in anticipation of such acquisition, unless the Lien was created to secure or provide for the payment of any part of the purchase price of such property or assets; and

(c)    any Lien created or outstanding on or over any asset of any entity which becomes a Significant Subsidiary on or after the date of the issuance of the notes, where the Lien is created prior to the date on which that entity becomes a Significant Subsidiary;

(6)   (a)    Liens required by any contract, statute or regulation in order to permit us or a Significant Subsidiary to perform any contract or subcontract made by it with or at the request of a governmental entity or any governmental department, agency or instrumentality, or to secure partial, progress, advance or any other payments by us or a Significant Subsidiary to such governmental unit under the provisions of any contract, statute or regulation;

(b)    any Lien securing industrial revenue, development, pollution control, solid waste disposal or similar bonds issued by or for our benefit or a Significant Subsidiary, provided that such industrial revenue, development, pollution control or similar bonds do not provide recourse generally to us and/or such Significant Subsidiary; and

(c)    any Lien securing taxes or assessments or other applicable governmental charges or levies;

(7)    any Lien which arises under any order of attachment, restraint or similar legal process arising in connection with court proceedings and any Lien which secures the reimbursement obligation for any bond obtained in connection with an appeal taken in any court proceeding, so long as the execution or other enforcement of such Lien arising under such legal process is effectively stayed and the claims secured by that Lien are being contested in good faith and, if appropriate, by appropriate legal proceedings, and any Lien in favor of a plaintiff or defendant in any action before a court or tribunal as security for costs and/or expenses;

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(8)    any extension, renewal or replacement (or successive extensions, renewals or replacements), as a whole or in part, of any Liens referred to in the foregoing clauses, for amounts not exceeding the principal amount of the Indebtedness secured by the Lien so extended, renewed or replaced, provided that such extension, renewal or replacement Lien is limited to all or a part of the same property or assets that were covered by the Lien extended, renewed or replaced (plus improvements on such property or assets);

(9)    any Lien created in connection with Project Finance Debt;

(10)    any Lien created by DP&L or its subsidiaries securing Indebtedness of DP&L or its subsidiaries;

(11)    any Lien created in connection with the securitization of some or all of the assets of DP&L and the associated issuance of Indebtedness as authorized by applicable state or federal law in connection with the restructuring of jurisdictional electric or gas businesses;

(12)    any Lien on stock created in connection with a mandatorily convertible or exchangeable stock or debt financing, provided that any such financing may not be secured by or otherwise involve the creation of a Lien on any capital stock of DP&L or any successor entity to DP&L; and

(13)    any Lien under one or more credit facilities for Indebtedness in an aggregate principal amount outstanding at any time not to exceed 10% of Consolidated Net Assets.

Restricted Payments

We shall not (1) declare, recommend, make or pay any Distribution to any of our shareholders or (2) make any intercompany loan to any of our Affiliates (other than us or any of our direct or indirect Subsidiaries) unless there exists no Event of Default and no such Event of Default will result from the making of such Distribution or intercompany loan and either:

(a)    at the time and as a result of such Distribution or intercompany loan, our Leverage Ratio does not exceed 0.67:1, and our Interest Coverage Ratio is not less than 2.5:1; or

(b)    if we are not in compliance with the foregoing ratios, at such time our senior long-term debt rating from two of the three Rating Agencies is at least Investment Grade.

Prior to making any Distribution or intercompany loan described above, our Board of Directors (including the Independent Director) shall confirm that such Distribution or intercompany loan complies with the terms of this covenant, provided that, in the case of a Distribution or intercompany loan to be made under the circumstances described in clause (a) in the first paragraph above, the Board of Directors shall have first obtained a compliance certificate from an officer of DPL that, at the time and after giving effect to such Distribution or intercompany loan, we are in compliance with the Leverage Ratio and the Interest Coverage Ratio set forth in clause (a) above; provided further that the foregoing approval will not be required in the case of intercompany loans if the aggregate amount of intercompany loans outstanding at any one time does not exceed $20 million.

Notwithstanding the foregoing limitation on Distributions and intercompany loans, we may declare and make (and each Subsidiary of us may declare and make to enable us to do the same) Distributions to AES so that AES may, and AES shall be permitted to, pay any Taxes which are attributable to our Consolidated Net Income as part of a consolidated group; provided, that in each case the amount of such Distributions in respect of any fiscal year does not exceed the amount that the Company and its Subsidiaries, as applicable, would have been required to pay in respect of the relevant Taxes for such fiscal year had the Company and/or its Subsidiaries, as applicable, (A) been liable for such Taxes separately from AES or any such other parent company or (B) if the Company is treated as a disregarded entity or partnership for U.S. federal, state and/or local income tax purposes for such period, were the Company a taxpayer and parent of a consolidated group (or otherwise liable for the taxes of its Subsidiaries) and had paid such taxes for the Company and/or its Subsidiaries.

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Reports and Other Information

At any time that we are not subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, or do not otherwise report on an annual and quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the Securities and Exchange Commission, the indenture requires us to deliver (which may be accomplished through the posting on the internet) to the trustee and to holders of the notes, without cost to any holder:

(1)    within 90 days after the end of each fiscal year, audited financial statements; and

(2)    within 45 days after the end of each of the first three fiscal quarters of each fiscal year, quarterly unaudited financial statements.

Events of Default

An Event of Default with respect to the notes is defined in the indenture as being:

(1)    default for 30 days in the payment of any interest on the notes;

(2)    default in the payment of principal of or any premium on, the notes at maturity, upon redemption, upon required purchase, upon acceleration or otherwise;

(3)    default in the performance, or breach, of any covenant or obligation in the indenture and continuance of the default or breach for a period of 30 days after written notice specifying the default is given to us by the trustee or to us and the trustee by the holders of at least 25% in aggregate principal amount of the notes;

(4)    default in the payment of the principal of any bond, debenture, note or other evidence of indebtedness, in each case for money borrowed, issued by us, or in the payment of principal under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for Borrowed Money, of us or any Significant Subsidiary if such Indebtedness for Borrowed Money is not Project Finance Debt and provides for recourse generally to us or any Significant Subsidiary, which default for payment of principal is in an aggregate principal amount exceeding $40 million when such indebtedness becomes due and payable (whether at maturity, upon redemption or acceleration or otherwise), if such default shall continue unremedied or unwaived for more than 30 business days and the time for payment of such amount has not been expressly extended (until such time as such payment default is remedied, cured or waived);

(5)    a court having jurisdiction enters a decree or order for:

· relief in respect of us or any of our Significant Subsidiaries in an involuntary case under any applicable bankruptcy, insolvency, or other similar law now or hereafter in effect; or

· appointment of a receiver, liquidator, assignee, custodian, trustee, sequestrator, or similar official of us or any of our Significant Subsidiaries or for all or substantially all of the property and assets of us or any of our Significant Subsidiaries; or

· the winding up or liquidation of our affairs or any of our Significant Subsidiaries;

· and, in either case, such decree or order remains unstayed and in effect for a period of 60 consecutive days; or

(6)    we or any of our Significant Subsidiaries:

· commences a voluntary case under any applicable bankruptcy, insolvency, or other similar law now or hereafter in effect, or consents to the entry of an order for relief in an involuntary case under any such law;

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· consents to the appointment of or taking possession by a receiver, liquidator, assignee, custodian, trustee, sequestrator, or similar official of us or any of our Significant Subsidiaries or for all or substantially all of the property and assets of us or any of our Significant Subsidiaries; or

· effects any general assignment for the benefit of creditors.

If an Event of Default (other than an Event of Default specified in clause (5) or (6) with respect to us) occurs and continues, then the trustee or the holders of at least 25% in principal amount of the notes then outstanding may, by written notice to us, and the trustee at the request of at least 25% in principal amount of the notes then outstanding will, declare the principal, premium, if any, and accrued interest on the outstanding notes to be immediately due and payable. Upon a declaration of acceleration, the principal, premium, if any, and accrued interest shall be immediately due and payable.

If an Event of Default specified in clause (5) or (6) above occurs with respect to us, the principal, premium, if any, and accrued interest on the notes shall be immediately due and payable, without any declaration or other act on the part of the trustee or any holder.

The holders of at least a majority in principal amount of the notes may, by written notice to us and to the trustee, waive all past defaults with respect to the notes and rescind and annul a declaration of acceleration with respect to the notes and its consequences if:

· all existing Events of Default applicable to the notes other than the nonpayment of the principal, premium, if any, and interest on the notes that have become due solely by that declaration of acceleration, have been cured or waived; and

· the rescission would not conflict with any judgment or decree of a court of competent jurisdiction.

No holder of the notes will have any right to institute any proceeding, judicial or otherwise, with respect to the indenture, or for the appointment of a receiver or trustee, or for any other remedy under the indenture, unless:

· such holder has previously given written notice to the trustee of a continuing Event of Default with respect to the notes;

· the holders of not less than 25% in principal amount of the notes shall have made written request to a responsible officer of the trustee to institute proceedings in respect of such Event of Default in its own name as trustee;

· such holder or holders have offered the trustee indemnity satisfactory to the trustee against the costs, expenses and liabilities to be incurred in compliance with such request;

· the trustee, for 60 days after its receipt of such notice, request and offer of indemnity, has failed to institute any such proceeding; and

· no direction inconsistent with such written request has been given to the trustee during such 60-day period by the holders of a majority in principal amount of the outstanding notes.

However, these limitations do not apply to the right of any holder of a note to receive payment of the principal, premium, if any, or interest on, that note or to bring suit for the enforcement of any payment, on or after the due date expressed in the notes, which right shall not be impaired or affected without the consent of the holder.

The indenture requires that certain of our officers certify, on or before a date not more than 120 days after the end of each fiscal year, that to the best of those officers’ knowledge, we have fulfilled all our obligations under the indenture. We are also obligated to notify the trustee of any default or defaults in the performance of any covenants or agreements under the indenture provided, however, that a failure by us to deliver such notice of a default shall not constitute a default under the indenture, if we have remedied such default within any applicable cure period.

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No Liability of Directors, Officers, Employees, Incorporators and Stockholders

No director, officer, employee, incorporator, member or stockholder of us, as such, will have any liability for any of our obligations under the notes or the indenture or for any claim based on, in respect of, or by reason of, such obligations. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. This waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the Securities and Exchange Commission that such a waiver is against public policy.

Amendments and Waivers

Amendments Without Consent of Holders. We and the trustee may amend or supplement the indenture or the notes without notice to or the consent of any holder:

(1)    to cure any ambiguity, defect or inconsistency in the indenture or the notes;

(2)    to comply with “—Merger, Consolidation, Sale, Lease or Conveyance;”

(3)    to comply with any requirements of the Securities and Exchange Commission in connection with the qualification of the indenture under the Trust Indenture Act;

(4)    to evidence and provide for the acceptance of appointment hereunder by a successor trustee;

(5)    to provide for any guarantee of the notes, to secure the notes or to confirm and evidence the release, termination or discharge of any guarantee of or lien securing the notes when such release, termination or discharge is permitted by the indenture;

(6)    to provide for or confirm the issuance of additional notes; or

(7)    to make any other change that does not materially and adversely affect the rights of any holder.

Amendments With Consent of Holders. (a) Except as otherwise provided in “—Events of Default” or paragraph (b), we and the trustee may amend the indenture with the written consent of the holders of a majority in principal amount of the outstanding notes and the holders of a majority in principal amount of the outstanding notes may waive future compliance by us with any provision of the indenture with respect to the notes.

(b)    Notwithstanding the provisions of paragraph (a), without the consent of each holder of notes, an amendment or waiver may not:

(1)    reduce the principal amount of or change the stated maturity of any installment of principal of the notes;

(2)    reduce the rate of or change the stated maturity of any interest payment on the notes;

(3)    reduce the amount payable upon the redemption of the notes, in respect of an optional redemption, change the times at which the notes may be redeemed or, once notice of redemption has been given, the time at which they must thereupon be redeemed;

(4)    make the notes payable in money other than that stated in the notes,

(5)    impair the right of any holder of notes to receive any principal payment or interest payment on such holder’s notes, on or after the stated maturity thereof, or to institute suit for the enforcement of any such payment,

(6)    make any change in the percentage of the principal amount of the notes required for amendments or waivers; or

(7)    modify or change any provision of the indenture affecting the ranking of the notes in a manner adverse to the holders of the notes.

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It is not necessary for holders to approve the particular form of any proposed amendment, supplement or waiver, but is sufficient if their consent approves the substance thereof.

Neither we nor any of our Subsidiaries or Affiliates may, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fee or otherwise, to any holder for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the indenture or the notes unless such consideration is offered to be paid or agreed to be paid to all holders of the notes that consent, waive or agree to amend such term or provision within the time period set forth in the solicitation documents relating to the consent, waiver or amendment.

Defeasance and Discharge

The indenture provides that we are deemed to have paid and will be discharged from all obligations in respect of the notes on the 123rd day after the deposit referred to below has been made, and that the provisions of the indenture will no longer be in effect with respect to the notes (except for, among other matters, certain obligations to register the transfer or exchange of the notes, to replace stolen, lost or mutilated notes, to maintain paying agencies and to hold monies for payment in trust) if, among other things,

(1)    we have deposited with the trustee, in trust, money and/or U.S. Government Obligations (as defined herein) that, through the payment of interest and principal in respect thereof, will provide money in an amount sufficient to pay the principal, premium, if any, and accrued interest on the notes, on the due date thereof or earlier redemption (irrevocably provided for under arrangements satisfactory to the trustee), as the case may be, in accordance with the terms of the indenture;

(2)    we have delivered to the trustee either:

· an opinion of counsel to the effect that beneficial owners of notes will not recognize income, gain or loss for federal income tax purposes as a result of the exercise of our option under this “Defeasance and Discharge” provision and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if the deposit, defeasance and discharge had not occurred, which opinion of counsel must be based upon a ruling of the Internal Revenue Service to the same effect unless there has been a change in applicable federal income tax law or related treasury regulations after the date of the indenture, or

· a ruling directed to the trustee received from the Internal Revenue Service to the same effect as the aforementioned opinion of counsel;

(3)    we have delivered to the trustee an opinion of counsel to the effect that the creation of the defeasance trust does not violate the Investment Company Act of 1940 and after the passage of 123 days following the deposit, the trust fund will not be subject to the effect of Section 547 of the U.S. Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law,

(4)    immediately after giving effect to that deposit on a pro forma basis, no Event of Default has occurred and is continuing on the date of the deposit or during the period ending on the 123rd day after the date of the deposit, and the deposit will not result in a breach or violation of, or constitute a default under, any other agreement or instrument to which we are a party or by which we are bound, and

(5)    if at that time any notes are listed on a national securities exchange, we have delivered to the trustee an opinion of counsel to the effect that the notes will not be delisted as a result of a deposit, defeasance and discharge.

As more fully described in the indenture, the indenture also provides for defeasance of certain covenants.

Notices

For so long as notes in global form are outstanding, notices to be given to holders of the notes will be given to the depositary, in accordance with its applicable policies as in effect from time to time. If notes are issued in definitive form, notices to be given to holders of the notes will be deemed to have been given upon the mailing by

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first class mail, postage prepaid, of such notices to holders of the notes at their registered addresses as they appear in the register.

Notices will be deemed to have been given on the date of mailing or of publication as aforesaid or, if published on different dates, on the date of the first such publication.

Concerning the Trustee

U.S. Bank National Association acts as the trustee under the indenture.

Except during the continuance of an Event of Default, the trustee need perform only those duties that are specifically set forth in the indenture and no others, and no implied covenants or obligations will be read into the indenture against the trustee. In case an Event of Default has occurred and is continuing, the trustee shall exercise those rights and powers vested in it by the indenture and use the same degree of care and skill in their exercise as a prudent person would exercise or use under the circumstances in the conduct of such person’s own affairs. No provision of the indenture requires the trustee to expend or risk its own funds or otherwise incur any financial liability in the performance of its duties or in the exercise of its rights or powers thereunder. The trustee shall be under no obligation to exercise any of the rights or powers vested in it by the indenture at the request or direction of any of the holders pursuant to the indenture, unless such holders shall have offered to the trustee security or indemnity satisfactory to the trustee against the costs, expenses and liabilities which might be incurred by it in compliance with such request or direction.

The indenture and provisions of the Trust Indenture Act incorporated by reference therein contain limitations on the rights of the trustee, should it become a creditor of us, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee is permitted to engage in other transactions with us and our Affiliates; provided that if it acquires any conflicting interest it must either eliminate the conflict within 90 days, apply to the Securities and Exchange Commission for permission to continue or resign.

Form, Denomination and Registration of Notes

Except as set forth below, the notes will be issued in registered, global form in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. The notes will be issued at the closing of this offering only against payment in immediately available funds.

The Global Notes will be deposited upon issuance with the trustee as custodian for DTC and registered in the name of DTC or its nominee, Cede & Co., in each case for credit to an account of a direct or indirect participant in DTC as described below. Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may be exchanged for Notes in certificated form. See “—Exchange of Global Notes for Certificated Notes.”

In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.

Depository Procedures

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We and the trustee take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly

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(collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants. DTC has also advised us that, pursuant to procedures established by it:

(1)    upon deposit of the Global Notes, DTC will credit the accounts of Participants with portions of the principal amount of the Global Notes; and

(2)    ownership of these interests in the Global Notes will be shown on, and the transfer of ownership thereof will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interest in the Global Notes).

All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems.

The laws of some states require that certain persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such persons will be limited to that extent. Because DTC can act only on behalf of the Participants, which in turn act on behalf of the Indirect Participants, the ability of a person having beneficial interests in a Global Note to pledge such interests to persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of interests in the Global Notes will not have notes registered in their names, will not receive physical delivery of notes in certificated form and will not be considered the registered owners or “holders” thereof under the indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the indenture. Under the terms of the indenture, we and the trustee will treat the persons in whose names the notes, including the Global Notes, are registered as the owners thereof for the purpose of receiving payments and for all other purposes. Consequently, neither we, the trustee, nor any agent of ours or the trustee’s has or will have any responsibility or liability for:

(1)    any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interest in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or

(2)    any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of the notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee or us. Neither we nor the trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the notes, and we and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes. Transfers between Participants in DTC will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

Subject to compliance with any transfer restrictions applicable to the notes described herein, crossmarket transfers between the Participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other

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hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by its respective depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

DTC has advised us that it will take any action permitted to be taken by a holder of the notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for legended notes in certificated form, and to distribute such notes to its Participants.

Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the Global Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. Neither we nor the trustee nor any of our or their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for definitive notes in registered certificated form (“Certificated Notes”) if:

(1)    DTC (a) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act, and in each case we fail to appoint a successor depositary within 90 days of that notice or becoming aware that DTC is no longer so registered or willing or able to act as a depositary;

(2)    we determine not to have the Notes represented by a Global Note and provide written notice thereof to the trustee; or

(3)    there shall have occurred and be continuing a Default or Event of Default with respect to the notes and DTC requests such exchange.

In all cases, certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be in registered form, registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).

Governing Law

The indenture and the notes are governed by, and construed in accordance with, the laws of the State of New York.

Certain Definitions

Set forth below are certain defined terms used in the indenture. We refer you to the indenture for a full disclosure of all such terms, as well as any other capitalized terms used in this section of the prospectus for which no definition is provided.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control” (including, with correlative meanings, the terms “controlling,” “controlled by” and “under common control with”), as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause

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the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise.

“Capitalized Lease Obligations” means all lease obligations of us and our Subsidiaries which, under GAAP, are or will be required to be capitalized, in each case taken at the amount of the lease obligation accounted for as indebtedness in conformity with those principles.

“Consolidated Current Liabilities” means the consolidated current liabilities of us and our Subsidiaries but excluding the current portion of long term Indebtedness which would otherwise be included in it, as determined on a consolidated basis in accordance with GAAP.

“Consolidated Debt” means, at any time, the sum of the aggregate outstanding principal amount of all Indebtedness for Borrowed Money (including, without limitation, the principal component of Capitalized Lease Obligations, but excluding Permitted Debt, Currency, Interest Rate or Commodity Agreements and all Consolidated Current Liabilities and Project Finance Debt) of us and our Subsidiaries, as determined on a consolidated basis in conformity with GAAP.

“Consolidated EBITDA” means, for any period, for us and our Subsidiaries on a consolidated basis, an amount equal to Consolidated Net Income for such period plus (a) the following to the extent deducted in calculating such Consolidated Net Income: (i) Consolidated Interest Expense for such period, (ii) the provision for Federal, state, local and foreign income taxes payable by us and our Subsidiaries for such period, (iii) depreciation and amortization expense for such period, (iv) other non-recurring expenses of us and our Subsidiaries reducing such Consolidated Net Income (x) which do not represent a cash item in such period or (y) which are cash items in such period that were incurred as a result of (A) the early termination of our Capital Trust II Indebtedness or (B) termination of existing swap contracts (it being understood that cash charges described in this clause (B) will not exceed $50,000,000 in the aggregate), (C) out-of-pocket third party costs and expenses incurred directly in connection with the implementation, negotiation, documentation and closing of the Separation Transactions or (D) normal and customary out-of-pocket third party costs, expenses and fees incurred directly in connection with the refinancing of any existing Indebtedness, and (v) all other non-cash items reducing Consolidated Net Income for such period, and minus (b) the following to the extent included in calculating such Consolidated Net Income: (i) Federal, state, local and foreign income tax credits of us and our Subsidiaries for such period and (ii) all non-cash items increasing Consolidated Net Income for such period.

“Consolidated Interest Expense” means, for any period, for us and our Subsidiaries on a consolidated basis, the sum of (a) all interest, premium payments, debt discount, fees, charges and related expenses of us and our Subsidiaries in connection with Indebtedness for Borrowed Money (including capitalized interest) or in connection with the deferred purchase price of assets, in each case to the extent treated as interest in accordance with GAAP, and (b) the portion of rent expense of us and our Subsidiaries with respect to such period under capital leases that is treated as interest in accordance with GAAP.

“Consolidated Net Assets” means the aggregate amount of assets (less reserves and other deductible items) after deducting current liabilities, as shown on the consolidated balance sheet of the Company and its subsidiaries contained in its latest audited financial statements and prepared in accordance with GAAP.

“Consolidated Net Income” means, for any period, the aggregate of the net income (or loss) of us and our Subsidiaries for such period, as determined on a consolidated basis in conformity with GAAP; provided that the following items shall be excluded from any calculation of Consolidated Net Income (without duplication): (i) the net income (or loss) of any Person (other than a Subsidiary) in which any other person has a joint interest, except to the extent of the amount of dividends or other distributions actually paid to us or another Subsidiary of us during such period; (ii) the net income (or loss) of any Subsidiary to the extent that the declaration or payment of dividends or similar distributions by such Subsidiary of such net income is not at the time permitted by the operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation or license; (iii) all extraordinary gains and extraordinary losses, merger related expenses and one-time expenses, cash or noncash, relating to restructuring efforts; and (iv) all gains and losses from discontinued operations.

“Currency, Interest Rate or Commodity Agreements” means an agreement or transaction involving any currency, interest rate or energy price or volumetric swap, cap or collar arrangement, forward exchange transaction, option, warrant, forward rate agreement, futures contract or other derivative instrument of any kind for the hedging

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or management of foreign exchange, interest rate or energy price or volumetric risks, it being understood, for purposes of this definition, that the term “energy” will include, without limitation, coal, gas, oil and electricity.

“Distribution” means any dividend, distribution or payment (including by way of redemption, repurchase, retirement, return or repayment) in respect of shares of capital stock of us, excluding any contract adjustment payments under contracts to purchase common stock of us, Parent or any of our Affiliates (which common stock was not held as an asset of us) entered into in connection with the issuance of any Permitted Debt.

“DTC” means The Depository Trust Company.

“Excluded Subsidiary” means any subsidiary of us:

(1)    in respect of which neither we nor any subsidiary of ours (other than another Excluded Subsidiary) has undertaken any legal obligation to give any guarantee for the benefit of the holders of any Indebtedness for Borrowed Money (other than to another member of the Group) other than in respect of any statutory obligation and the subsidiaries of which are all Excluded Subsidiaries; and

(2)    which has been designated as such by us by written notice to the trustee; provided that we may give written notice to the trustee at any time that any Excluded Subsidiary is no longer an Excluded Subsidiary whereupon it shall cease to be an Excluded Subsidiary.

“Fitch” means Fitch Ratings Inc.

“GAAP” means generally accepted accounting principles in the United States as in effect from time to time.

“Group” means DPL and its subsidiaries and “member of the Group” shall be construed accordingly.

“Indebtedness” means, with respect to us or any of our subsidiaries at any date of determination (without duplication):

(1)    all Indebtedness for Borrowed Money (excluding any credit which is available but undrawn);

(2)    all obligations in respect of letters of credit (including reimbursement obligations with respect to letters of credit);

(3)    all obligations to pay the deferred and unpaid purchase price of property or services, which purchase price is due more than six months after the date of placing such property in service or taking delivery and title to the property or the completion of such services, except trade payables;

(4)    all Capitalized Lease Obligations;

(5)    all indebtedness of other persons secured by a mortgage, charge, lien, pledge or other security interest on any asset of us or any of our subsidiaries, whether or not such indebtedness is assumed; provided that the amount of such Indebtedness must be the lesser of: (a) the fair market value of such asset at such date of determination and (b) the amount of the secured indebtedness;

(6)    all indebtedness of other persons of the types specified in the preceding clauses (1) through (5), to the extent such indebtedness is guaranteed by us or any of our subsidiaries; and

(7)    to the extent not otherwise included in this definition, net obligations under Currency, Interest Rate or Commodity Agreements.

The amount of Indebtedness at any date will be the outstanding balance at such date of all unconditional obligations as described above and, upon the occurrence of the contingency giving rise to the obligation, the maximum liability of any contingent obligations of the types specified in the preceding clauses (1) through (7) at such date; provided that the amount outstanding at any time of any Indebtedness issued with original issue discount is the face amount of such Indebtedness less the remaining unamortized portion of the original issue discount of such Indebtedness at such time as determined in conformity with GAAP.

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“Indebtedness For Borrowed Money” means any indebtedness (whether being principal, premium, interest or other amounts) for:

· money borrowed;

· payment obligations under or in respect of any trade acceptance or trade acceptance credit; or

· any notes, bonds, loan stock or other debt securities offered, issued or distributed whether by way of public offer, private placement, acquisition consideration or otherwise and whether issued for cash or in whole or in part for a consideration other than cash;

provided, however, in each case, that such term will exclude:

· any indebtedness relating to any accounts receivable securitizations;

· any Indebtedness of the type permitted to be secured by Liens pursuant to clause (12) under the caption “—Limitations on Liens” described above; and

· any Preferred Securities which are issued and outstanding on the date of original issue of the notes or any extension, renewal or replacement (or successive extensions, renewals or replacements), as a whole or in part, of any such existing Preferred Securities, for amounts not exceeding the principal amount or liquidation preference of the Preferred Securities so extended, renewed or replaced.

“Independent Director” shall mean a director of us who, if we are listed on the New York Stock Exchange, meets the standards for independence set forth in the New York Stock Exchange Listing Standards, or if such standards are not applicable to us, who shall at no time be, or have been, a director, officer, stockholder, associate, customer or supplier of, be employed by, or hold or held at any time (directly or indirectly) any beneficial economic interest in us or our Parent or any subsidiary or Affiliate of Parent (excluding such director’s position as such Independent Director of us and any compensation received by such director in such capacity).

“Interest Coverage Ratio” means, with respect to us on any Measurement Date, the ratio of (i) the aggregate amount of Consolidated EBITDA of us for the four fiscal quarters for which financial information in respect thereof is available immediately prior to such Measurement Date to (ii) the aggregate Consolidated Interest Expense during such four fiscal quarters.

“Investment Grade” means BBB- or higher by S&P, BBB- or higher by Fitch or Baa3 or higher by Moody’s, or the equivalent of such global ratings by S&P, Fitch or Moody’s.

“Leverage Ratio” means the ratio of Consolidated Debt to Total Capital (as defined herein), calculated on the basis of the most recently available consolidated balance sheet of us and our consolidated Subsidiaries (provided that such balance sheet is as of a date not more than 60 days prior to a Measurement Date) prepared in accordance with GAAP.

“Lien” means any mortgage, lien, pledge, security interest or other encumbrance; provided, however, that the term “Lien” does not mean any easements, rights-of-way, restrictions and other similar encumbrances and encumbrances consisting of zoning restrictions, leases, subleases, restrictions on the use of property or defects in title.

“Measurement Date” means the record date for any Distribution.

“Moody’s” means Moody’s Investors Service, Inc.

“Parent” shall mean any entity which owns directly or indirectly, 10% or more of the outstanding common shares of us.

“Permitted Debt” means Indebtedness for Borrowed Money issued in connection with a contract or contracts to purchase from us common stock of us, Parent or any Affiliate of Parent (which common stock was not held as an

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asset of us) for an aggregate amount equal to the aggregate principal amount of such Indebtedness for Borrowed Money.

“Person” means any individual, corporation, limited liability company, partnership, joint venture, association, joint-stock company, trust, unincorporated organization or government or any agency or political subdivision thereof.

“Preferred Securities” means, without duplication, any trust preferred or preferred securities or related debt or guaranties of us or any of our subsidiaries.

“Project Finance Debt” means:

· any Indebtedness to finance or refinance the ownership, acquisition, development, design, engineering, procurement, construction, servicing, management and/or operation of any project or asset which is incurred by an Excluded Subsidiary; and

· any Indebtedness to finance or refinance the ownership, acquisition, development, design, engineering, procurement, construction, servicing, management and/or operation of any project or asset in respect of which the person or persons to whom any such Indebtedness is or may be owed by the relevant borrower (whether or not a member of the Group) has or have no recourse whatsoever to any member of the Group (other than an Excluded Subsidiary) for the repayment of that Indebtedness other than: (i) recourse to such member of the Group for amounts limited to the cash flow or net cash flow (other than historic cash flow or historic net cash flow) from, or ownership interests or other investments in, such project or asset; and/or (ii) recourse to such member of the Group for the purpose only of enabling amounts to be claimed in respect of such Indebtedness in an enforcement of any encumbrance given by such member of the Group over such project or asset or the income, cash flow or other proceeds deriving from the project (or given by any shareholder or the like, or other investor in, the borrower or in the owner of such project or asset over its shares or the like in the capital of, or other investment in, the borrower or in the owner of such project or asset) to secure such Indebtedness, provided that the extent of such recourse to such member of the Group is limited solely to the amount of any recoveries made on any such enforcement; and/or (iii) recourse to such borrower generally, or directly or indirectly to a member of the Group, under any form of assurance, indemnity, undertaking or support, which recourse is limited to a claim for damages (other than liquidated damages and damages required to be calculated in a specified way) for breach of an obligation (not being a payment obligation or an obligation to procure payment by another or an indemnity in respect of a payment obligation, or any obligation to comply or to procure compliance by another with any financial ratios or other tests of financial condition) by the person against which such recourse is available.

“S&P” means Standard & Poor’s Rating Services, a division of The McGraw-Hill Companies, Inc.

“Separation Transactions” means the restructuring of DP&L operations in accordance with an order by the PUCO, including the separation of DP&L’s generation assets from its transmission and distribution assets, in compliance with the laws of the state of Ohio.

“Significant Subsidiary” means, at any particular time, any subsidiary of ours whose gross assets or gross revenues (having regard to our direct and/or indirect beneficial interest in the shares, or the like, of that subsidiary) represent at least 25% of the consolidated gross assets or, as the case may be, consolidated gross revenues of us.

“Subsidiary” means, with respect to any person, any corporation, association, partnership, limited liability company or other business entity of which 50% or more of the total voting power of shares of capital stock or other interests (including partnership interests) entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees is at the time owned, directly or indirectly, by (1) such person, (2) such person and one or more subsidiaries of such person or (3) one or more subsidiaries of such person.

“Taxes” means all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any governmental authority, including any interest, additions to tax or penalties applicable thereto.

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“Total Capital” of any Person means, as of any date, the sum (without duplication) of (a) Indebtedness for Borrowed Money, (b) preferred stock and Preferred Securities of such Person and its consolidated Subsidiaries, (c) consolidated stockholder’s equity of such Person and its consolidated Subsidiaries (excluding any preferred stock in stockholder’s equity) and (d) any excess of the value of our assets acquired by Parent over the book value of such assets.

“U.S. Government Obligation” means any:

(1) security which is: (a) a direct obligation of the United States for the payment of which the full faith and credit of the United States is pledged or (b) an obligation of a person controlled or supervised by and acting as an agency or instrumentality of the United States the payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States, which, in the case of clause (a) or (b), is not callable or redeemable at the option of the issuer of the obligation, and

(2) depositary receipt issued by a bank (as defined in the Securities Act) as custodian with respect to any security specified in clause (1) above and held by such bank for the account of the holder of such depositary receipt or with respect to any specific payment of principal of or interest on any such security held by any such bank, provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligation or the specific payment of interest on or principal of the U.S. Government Obligation evidenced by such depositary receipt.

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The Exchange Offer

General

We hereby offer to exchange a like principal amount of new notes for any or all outstanding old notes on the terms and subject to the conditions set forth in this prospectus and accompanying letter of transmittal.  We often refer to this offer as the “exchange offer.” You may tender some or all of your outstanding old notes pursuant to this exchange offer. As of the date of this prospectus, $200,000,000 aggregate principal amount of the old notes are outstanding. Our obligation to accept old notes for exchange pursuant to the exchange offer is subject to certain conditions set forth hereunder.

Purpose and Effect of the Exchange Offer

In connection with the offering of the old notes, which was consummated on October 6, 2014, we entered into a registration rights agreement with the initial purchasers of the old notes, under which we agreed:

(1)    to use our reasonable best efforts to cause to be filed a registration statement on or prior to 270 days after the closing of the offering of the old notes with respect to an offer to exchange the old notes for a new issue of securities, with terms substantially the same as of the old notes but registered under the Securities Act;

(2)    to use our best efforts to cause the registration statement to be declared effective by the SEC and remain effective until the closing of the exchange offer; and

(3)    to use our best efforts to consummate the exchange offer and issue the new notes within 390 days after the closing of the old notes offering.

The registration rights agreement provides that, if (a) we do not consummate the exchange offer registration on or prior to the date that is 390 days following the issuance of the old notes (the “exchange offer closing deadline”) or (b) we have not caused to become effective a shelf registration statement by the 90th day after such obligation arises (the “shelf effectiveness deadline”) (which in no event, however, shall be earlier than the exchange offer closing deadline), the interest rate for the notes will increase by a rate of 0.25% per annum during the first 90-day period immediately following the exchange offer closing deadline or the shelf effectiveness deadline, as applicable, and such increased rate will further increase by 0.25% per annum beginning on the 91^st day following the exchange offer closing deadline or the shelf effectiveness deadline, as applicable. In no event shall such increases exceed in the aggregate 0.50% per annum. Once the exchange offer is completed or the shelf registration statement is declared effective, as applicable, we will no longer be required to pay additional interest on the old notes. The additional interest rate for the old notes will not any time exceed 0.50% per annum notwithstanding our failure to meet more than one of these requirements.

The exchange offer is not being made to, nor will we accept tenders for exchange from, holders of old notes in any jurisdiction in which the exchange offer or acceptance of the exchange offer would violate the securities or blue sky laws of that jurisdiction. Furthermore, each holder of old notes that wishes to exchange their old notes for new notes in this exchange offer will be required to make certain representations as set forth herein.

Terms of the Exchange Offer; Period for Tendering Old Notes

This prospectus and the accompanying letter of transmittal contain the terms and conditions of the exchange offer.  Upon the terms and subject to the conditions included in this prospectus and in the accompanying letter of transmittal, which together are the exchange offer, we will accept for exchange old notes which are properly tendered on or prior to the expiration date, unless you have previously withdrawn them.

· When you tender to us old notes as provided below, our acceptance of the old notes will constitute a binding agreement between you and us upon the terms and subject to the conditions in this prospectus and in the accompanying letter of transmittal.

· For each $2,000 principal amount of old notes (and $1,000 principal amount of old notes in excess thereof) surrendered to us in the exchange offer, we will give you $2,000 principal amount of new notes (and

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$1,000 principal amount of new notes in excess thereof). Outstanding notes may only be tendered in denominations of $2,000 and integral multiples of $1,000 in excess thereof.

· We will keep the exchange offer open for not less than 20 business days, or longer if required by applicable law, after the date that we first mail notice of the exchange offer to the holders of the old notes.  We are sending this prospectus, together with the letter of transmittal, on or about the date of this prospectus to all of the registered holders of old notes at their addresses listed in the trustee’s security register with respect to the old notes.

· The exchange offer expires at 11:59 P.M., New York City time, on July 13, 2015; provided, however, that we, in our sole discretion, may extend the period of time for which the exchange offer is open.  The term “expiration date” means July 13, 2015 or, if extended by us, the latest time and date to which the exchange offer is extended.

· As of the date of this prospectus, $200,000,000 aggregate principal amount of the old notes were outstanding.  The exchange offer is not conditioned upon any minimum principal amount of old notes being tendered.

· Our obligation to accept old notes for exchange in the exchange offer is subject to the conditions that we describe in the section called “Conditions to the Exchange Offer” below.

· We expressly reserve the right, at any time, to extend the period of time during which the exchange offer is open, and thereby delay acceptance of any old notes, by giving oral or written notice of an extension to the exchange agent and notice of that extension to the holders as described below.  During any extension, all old notes previously tendered will remain subject to the exchange offer unless withdrawal rights are exercised.  Any old notes not accepted for exchange for any reason will be returned without expense to the tendering holder promptly following the expiration or termination of the exchange offer.

· We expressly reserve the right to amend or terminate the exchange offer, and not to accept for exchange any old notes that we have not yet accepted for exchange, if any of the conditions of the exchange offer specified below under “Conditions to the Exchange Offer” are not satisfied.  In the event of a material change in the exchange offer, including the waiver of a material condition, we will extend the offer period if necessary so that at least five business days remain in the exchange offer following notice of the material change.

· We will give oral or written notice of any extension, amendment, termination or non-acceptance described above to holders of the old notes promptly.  If we extend the expiration date, we will give notice by means of a press release or other public announcement no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date.  Without limiting the manner in which we may choose to make any public announcement and subject to applicable law, we will have no obligation to publish, advertise or otherwise communicate any public announcement other than by issuing a release to Dow Jones and Company News Agency and/or other similar news service.

· Holders of old notes do not have any appraisal or dissenters’ rights in connection with the exchange offer.

· Old notes which are not tendered for exchange or are tendered but not accepted in connection with the exchange offer will remain outstanding and be entitled to the benefits of the indenture, but will not be entitled to any further registration rights under the registration rights agreement.

· We intend to conduct the exchange offer in accordance with the applicable requirements of the Exchange Act and the rules and regulations of the SEC thereunder.

· By executing, or otherwise becoming bound by, the letter of transmittal, you will be making the representations described below to us.  See “—Resales of the New Notes.”

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Important rules concerning the exchange offer

You should note that:

· All questions as to the validity, form, eligibility, time of receipt and acceptance of old notes tendered for exchange will be determined by us in our sole discretion, which determination shall be final and binding.

· We reserve the absolute right to reject any and all tenders of any particular old notes not properly tendered or to not accept any particular old notes which acceptance might, in our judgment or the judgment of our counsel, be unlawful.

· We also reserve the absolute right to waive any defects or irregularities or conditions of the exchange offer as to any particular old notes either before or after the expiration date, including the right to waive the ineligibility of any holder who seeks to tender old notes in the exchange offer.  Unless we agree to waive any defect or irregularity in connection with the tender of old notes for exchange, you must cure any defect or irregularity within any reasonable period of time as we shall determine.

· Our interpretation of the terms and conditions of the exchange offer as to any particular old notes either before or after the expiration date shall be final and binding on all parties.

· Neither DPL Inc., the exchange agent nor any other person shall be under any duty to give notification of any defect or irregularity with respect to any tender of old notes for exchange, nor shall any of them incur any liability for failure to give any notification.

Procedures for Tendering Old Notes

What to submit and how

If you, as the registered holder of an old note, wish to tender your old notes for exchange in the exchange offer, you must contact a DTC participant to complete the book-entry transfer procedures described below, or otherwise complete and transmit a properly completed and duly executed letter of transmittal to U.S. Bank National Association at the address set forth below under “Exchange Agent” on or prior to the expiration date.

In addition,

(1)    certificates for old notes must be received by the exchange agent along with the letter of transmittal or

(2)    a timely confirmation of a book-entry transfer of old notes, if such procedure is available, into the exchange agent’s account at DTC using the procedure for book-entry transfer described below, must be received by the exchange agent prior to the expiration date, or

(3)    you must comply with the guaranteed delivery procedures described below.

The method of delivery of old notes, letters of transmittal and notices of guaranteed delivery is at your election and risk.  If delivery is by mail, we recommend that registered mail, properly insured, with return receipt requested, be used.  In all cases, sufficient time should be allowed to assure timely delivery.  No letters of transmittal or old notes should be sent to DPL Inc.

How to sign your letter of transmittal and other documents

Signatures on a letter of transmittal or a notice of withdrawal, as the case may be, must be guaranteed unless the old notes being surrendered for exchange are tendered

(1)    by a registered holder of the old notes who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal or

(2)    for the account of an eligible institution.

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If signatures on a letter of transmittal or a notice of withdrawal, as the case may be, are required to be guaranteed, the guarantees must be by any of the following eligible institutions:

· a firm which is a member of a registered national securities exchange or a member of the Financial Industry Regulatory Authority, Inc. or

· a commercial bank or trust company having an office or correspondent in the United States.

If the letter of transmittal is signed by a person or persons other than the registered holder or holders of old notes, the old notes must be endorsed or accompanied by appropriate powers of attorney, in either case signed exactly as the name or names of the registered holder or holders that appear on the old notes and with the signature guaranteed.

If the letter of transmittal or any old notes or powers of attorney are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers or corporations or others acting in a fiduciary or representative capacity, the person should so indicate when signing and, unless waived by DPL Inc., proper evidence satisfactory to DPL Inc. of its authority to so act must be submitted.

Acceptance of Old Notes for Exchange; Delivery of New Notes

Once all of the conditions to the exchange offer are satisfied or waived, we will accept, promptly after the expiration date, all old notes properly tendered and will issue the new notes promptly after the expiration of the exchange offer.  See “Conditions to the Exchange Offer” below.  For purposes of the exchange offer, our giving of oral or written notice of our acceptance to the exchange agent will be considered our acceptance of the exchange offer.

In all cases, we will issue new notes in exchange for old notes that are accepted for exchange only after timely receipt by the exchange agent of:

· certificates for old notes, or

· a timely book-entry confirmation of transfer of old notes into the exchange agent’s account at DTC using the book-entry transfer procedures described below, and

· a properly completed and duly executed letter of transmittal.

If we do not accept any tendered old notes for any reason included in the terms and conditions of the exchange offer or if you submit certificates representing old notes in a greater principal amount than you wish to exchange, we will return any unaccepted or non-exchanged old notes without expense to the tendering holder or, in the case of old notes tendered by book-entry transfer into the exchange agent’s account at DTC using the book-entry transfer procedures described below, non-exchanged old notes will be credited to an account maintained with DTC promptly following the expiration or termination of the exchange offer.

Book-Entry Transfer

The exchange agent will make a request to establish an account with respect to the old notes at DTC for purposes of the exchange offer promptly after the date of this prospectus.  Any financial institution that is a participant in DTC’s systems may make book-entry delivery of old notes by causing DTC to transfer old notes into the exchange agent’s account in accordance with DTC’s Automated Tender Offer Program procedures for transfer.  However, the exchange for the old notes so tendered will only be made after timely confirmation of book-entry transfer of old notes into the exchange agent’s account, and timely receipt by the exchange agent of an agent’s message, transmitted by DTC and received by the exchange agent and forming a part of a book-entry confirmation.  The agent’s message must state that DTC has received an express acknowledgment from the participant tendering old notes that are the subject of that book-entry confirmation that the participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce the agreement against that participant.

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Although delivery of old notes may be effected through book-entry transfer into the exchange agent’s account at DTC, the letter of transmittal, or a facsimile copy, properly completed and duly executed, with any required signature guarantees, must in any case be delivered to and received by the exchange agent at its address listed under “—Exchange Agent” on or prior to the expiration date.

If your old notes are held through DTC, you must complete a form called “instructions to registered holder and/or book-entry participant,” which will instruct the DTC participant through whom you hold your securities of your intention to tender your old notes or not tender your old notes.  Please note that delivery of documents to DTC in accordance with its procedures does not constitute delivery to the exchange agent and we will not be able to accept your tender of notes until the exchange agent receives a letter of transmittal and a book-entry confirmation from DTC with respect to your notes.  A copy of that form is available from the exchange agent.

Guaranteed Delivery Procedures

If you are a registered holder of old notes and you want to tender your old notes but your old notes are not immediately available, or time will not permit your old notes to reach the exchange agent before the expiration date, or the procedure for book-entry transfer cannot be completed on a timely basis, a tender may be effected if:

· the tender is made through an eligible institution,

· prior to the expiration date, the exchange agent receives, by facsimile transmission, mail or hand delivery, from that eligible institution a properly completed and duly executed letter of transmittal and notice of guaranteed delivery, substantially in the form provided by us, stating:

· the name and address of the holder of old notes;

· the amount of old notes tendered;

· the tender is being made by delivering that notice; and

· guaranteeing that within three New York Stock Exchange trading days after the date of execution of the notice of guaranteed delivery, the certificates of all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, as the case may be, will be deposited by that eligible institution with the exchange agent, and

· the certificates for all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, as the case may be, are received by the exchange agent within three New York Stock Exchange trading days after the date of execution of the Notice of Guaranteed Delivery.

Withdrawal Rights

You can withdraw your tender of old notes at any time on or prior to the expiration date.

For a withdrawal to be effective, a written notice of withdrawal must be received by the exchange agent at one of the addresses listed below under “Exchange Agent.”  Any notice of withdrawal must specify:

· the name of the person having tendered the old notes to be withdrawn

· the old notes to be withdrawn

· the principal amount of the old notes to be withdrawn

· if certificates for old notes have been delivered to the exchange agent, the name in which the old notes are registered, if different from that of the withdrawing holder

· if certificates for old notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of those certificates, you must also submit the serial numbers of the particular certificates to be

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withdrawn and a signed notice of withdrawal with signatures guaranteed by an eligible institution unless you are an eligible institution; and

· if old notes have been tendered using the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn old notes and otherwise comply with the procedures of that facility.

Please note that all questions as to the validity, form, eligibility and time of receipt of notices of withdrawal will be determined by us, and our determination shall be final and binding on all parties.  Any old notes so withdrawn will be considered not to have been validly tendered for exchange for purposes of the exchange offer. If you have properly withdrawn old notes and wish to re-tender them, you may do so by following one of the procedures described under “Procedures for Tendering Old Notes” above at any time on or prior to the expiration date.

Conditions to the Exchange Offer

Notwithstanding any other provisions of the exchange offer, we will not be required to accept for exchange, or to issue new notes in exchange for, any old notes and may terminate or amend the exchange offer, if at any time before the expiration of the exchange offer, that acceptance or issuance would violate applicable law or any interpretation of the staff of the SEC.

That condition is for our sole benefit and may be asserted by us regardless of the circumstances giving rise to that condition.  Our failure at any time to exercise the foregoing rights shall not be considered a waiver by us of that right.  Our rights described in the prior paragraph are ongoing rights which we may assert at any time and from time to time prior to the expiration of the exchange offer.

In addition, we will not accept for exchange any old notes tendered, and no new notes will be issued in exchange for any old notes, if at that time any stop order shall be threatened or in effect with respect to the exchange offer to which this prospectus relates or the qualification of the indenture under the Trust Indenture Act.

Exchange Agent

U.S. Bank National Association has been appointed as the exchange agent for the exchange offer. All executed letters of transmittal should be directed to the exchange agent at one of the addresses set forth below. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery should be directed to the exchange agent, addressed as follows:

Deliver To:

By Registered, Regular or Certified Mail or Overnight Delivery:

U.S. Bank National Association
Attn: Corporate Trust-Specialized Finance
111 Fillmore Avenue E
St. Paul, Minnesota 55107

Facsimile Transmissions:

651-466-7367

To Confirm by Email:

cts.specfinance@usbank.com

To Confirm by Telephone or for Information:

800-934-6802

Delivery to an address other than as listed above or transmission of instructions via facsimile other than as listed above does not constitute a valid delivery.

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Fees and Expenses

The principal solicitation is being made by mail; however, additional solicitation may be made by telegraph, telephone or in person by our officers, regular employees and affiliates.  We will not pay any additional compensation to any of our officers and employees who engage in soliciting tenders.  We will not make any payment to brokers, dealers, or others soliciting acceptances of the exchange offer.  However, we will pay the exchange agent reasonable and customary fees for its services and will reimburse it for its reasonable out-of-pocket expenses in connection with the exchange offer.

The estimated cash expenses to be incurred in connection with the exchange offer, including legal, accounting, SEC filing, printing and exchange agent expenses, will be paid by us and are estimated in the aggregate to be $425,000.

Accounting Treatment

We will record the new notes in our accounting records at the same carrying value as the old notes, which is the aggregate principal amount as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes upon the consummation of this exchange offer.  We will capitalize the expenses of this exchange offer and amortize them over the life of the notes.

Transfer Taxes

Holders who tender their old notes for exchange will not be obligated to pay any transfer taxes in connection therewith, except that holders who instruct us to register new notes in the name of, or request that old notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder will be responsible for the payment of any applicable transfer tax thereon.

Resale of the New Notes

Under existing interpretations of the staff of the SEC contained in several no-action letters to third parties, the new notes would in general be freely transferable after the exchange offer without further registration under the Securities Act.  The relevant no-action letters include the Exxon Capital Holdings Corporation letter, which was made available by the SEC on May 13, 1988, and the Morgan Stanley & Co. Incorporated letter, made available on June 5, 1991.

However, any purchaser of old notes who is an “affiliate” of DPL Inc. or who intends to participate in the exchange offer for the purpose of distributing the new notes

(1)    will not be able to rely on the interpretation of the staff of the SEC,

(2)    will not be able to tender its old notes in the exchange offer and

(3)   must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the securities unless that sale or transfer is made using an exemption from those requirements.

By executing, or otherwise becoming bound by, the Letter of Transmittal each holder of the old notes will represent that:

(1)    it is not our “affiliate”;

(2)    any new notes to be received by it were acquired in the ordinary course of its business; and

(3)    it has no arrangement or understanding with any person to participate, and is not engaged in and does not intend to engage, in the “distribution,” within the meaning of the Securities Act, of the new notes.

In addition, in connection with any resales of new notes, any broker-dealer participating in the exchange offer who acquired securities for its own account as a result of market-making or other trading activities must deliver a prospectus meeting the requirements of the Securities Act. The SEC has taken the position in the Shearman &

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Sterling no-action letter, which it made available on July 2, 1993, that participating broker-dealers may fulfill their prospectus delivery requirements with respect to the new notes, other than a resale of an unsold allotment from the original sale of the old notes, with the prospectus contained in the exchange offer registration statement. Under the registration rights agreement, we are required to allow participating broker-dealers and other persons, if any, subject to similar prospectus delivery requirements to use this prospectus as it may be amended or supplemented from time to time, in connection with the resale of new notes.

Failure to Exchange

Holders of old notes who do not exchange their old notes for new notes under the exchange offer will remain subject to the restrictions on transfer of such old notes as set forth in the legend printed on the notes as a consequence of the issuance of the old notes pursuant to the exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws, and otherwise set forth in the confidential offering memorandum distributed in connection with the private offering of the old notes.

Other

Participating in the exchange offer is voluntary, and you should carefully consider whether to accept. You are strongly urged to consult your financial, legal and tax advisors in making your own decision on what action to take.

U.S. Federal Income Tax Consequences of the Exchange Offer

The exchange of old notes for new notes in the exchange offer will not be a taxable event for holders.  When a holder exchanges an old note for a new note in the exchange offer, the holder will have the same adjusted tax basis and holding period in the new note as in the old note immediately before the exchange.

Persons considering the exchange of old notes for new notes should consult their own tax advisers concerning the U.S. federal income tax consequences in light of their particular situations as well as any tax consequences arising under the laws of any other taxing jurisdiction.

Plan of Distribution

Each broker-dealer that receives new notes for its own account in the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of new notes.  This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where old notes were acquired as a result of market-making activities or other trading activities.  We have agreed that, for a period of 90 days after the expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any resale of new notes received by it in exchange for old notes.

We will not receive any proceeds from any sale of new notes by broker-dealers.

New notes received by broker-dealers for their own account in the exchange offer may be sold from time to time in one or more transactions:

· in the over-the-counter market;

· in negotiated transactions;

· through the writing of options on the new notes; or

· a combination of those methods of resale,

at market prices prevailing at the time of resale, at prices related to prevailing market prices or negotiated prices.

Any resale may be made:

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· directly to purchasers; or

· to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any broker-dealer or the purchasers of any new notes.

Any broker-dealer that resells new notes that were received by it for its own account in the exchange offer and any broker or dealer that participates in a distribution of those new notes may be considered to be an “underwriter” within the meaning of the Securities Act.  Any profit on any resale of those new notes and any commission or concessions received by any of those persons may be considered to be underwriting compensation under the Securities Act.  The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be considered to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 90 days after the expiration date, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests those documents in the letter of transmittal.  We have agreed to pay all expenses incident to the exchange offer, other than commissions or concessions of any brokers or dealers and will indemnify the holders of the securities, including any broker-dealers, against some liabilities, including liabilities under the Securities Act.

Validity of Securities

Davis Polk & Wardwell LLP will opine for us on whether the new notes are valid and binding obligations of DPL Inc. and will rely on the opinion of Judi L. Sobecki, General Counsel of DPL Inc. with respect to certain matters under the laws of the State of Ohio.

Experts

The consolidated financial statements of DPL Inc. at December 31, 2014 and 2013, and for each of the three years in the period ended December 31, 2014, and the related consolidated financial statement schedule, “Schedule II—Valuation and Qualifying Accounts”, appearing in this registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Where You Can Find More Information

We have filed with the SEC, Washington, D.C. 20549, a registration statement on Form S-4 under the Securities Act with respect to our offering of the new notes. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto.  For further information with respect to the company and the new notes, reference is made to the registration statement and the exhibits and any schedules filed therewith. Statements contained in this prospectus as to the contents of any contract or other document referred to are not necessarily complete and in each instance, if such contract or document is filed as an exhibit, reference is made to the copy of such contract or other document filed as an exhibit to the registration statement, each statement being qualified in all respects by such reference. A copy of the registration statement, including the exhibits and schedules thereto, may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet website that contains reports, proxy statements and other information about issuers, like us, that file electronically with the SEC.  The address of that site is at http://www.sec.gov.

If for any reason we are not required to comply with the reporting requirements of the Securities Exchange Act of 1934, as amended, or we do not otherwise report on an annual or quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the SEC, we are still required under the indenture to deliver (which may be accomplished through posting on the internet) to the trustee and to holders of the notes, without any cost to any holder: (1) within 90 days after the end of each fiscal year, audited financial statements and (2) within 45 days after the end of each of the first three fiscal quarters of each fiscal year, quarterly unaudited financial statements. We are also required

109

under the indenture to provide without charge upon the written request of (1) a holder of any notes or (2) a prospective holder of any of the notes who is a “qualified institutional buyer” within the meaning of Rule 144A and is designated by an existing holder of any of the notes with the information with respect to the Company required to be delivered under Rule 144A(d)(f) under the Securities Act to enable resales of the notes to be made pursuant to Rule 144A.

Any such requests should be directed to us at: DPL Inc., 1065 Woodman Drive, Dayton, Ohio 45432, Phone: (937) 224-6000, Attention: Treasurer.

We also maintain an Internet site at http://www.dplinc.com.  Our website and the information contained therein or connected thereto shall not be deemed to be a part of this prospectus or the registration statement of which it forms a part.

110

Index to Financial Statements

DPL Inc. Annual Consolidated Financial Statements December 31, 2014, 2013 and 2012	Page No.
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Statements of Operations	F-3
Consolidated Statements of Comprehensive Loss	F-4
Consolidated Statements of Cash Flows	F-5
Consolidated Balance Sheets	F-7
Consolidated Statements of Shareholders’ Equity	F-9
Notes to Consolidated Financial Statements	F-10
Schedule II — Valuation and Qualifying Accounts	F-63
DPL Inc. Condensed Consolidated Financial Statements March 31, 2015
Condensed Consolidated Statements of Operations	F-65
Condensed Consolidated Statements of Comprehensive Loss	F-66
Condensed Consolidated Statements of Cash Flows	F-67
Condensed Consolidated Balance Sheets	F-68
Notes to Condensed Consolidated Financial Statements	F-70

F-1

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, 2014 and 2013, 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, 2014. 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, 2014. 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, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, 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 25, 2015

Indianapolis, Indiana

F-2

DPL INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year ended December 31,
$ in millions	2014			2013			2012
Revenues	$	1,763.0		$	1,636.9		$	1,668.4
Cost of revenues:
Fuel		304.5			366.7			361.9
Purchased power		592.6			389.0			342.1
Amortization of intangibles		1.2			7.1			95.1
Total cost of revenues		898.3			762.8			799.1
Gross margin		864.7			874.1			869.3
Operating expenses:
Operation and maintenance		388.3			396.7			406.4
Depreciation and amortization		139.8			132.9			125.4
General taxes		91.7			80.9			79.5
Goodwill impairment		135.8			306.3			1,817.2
Fixed-asset impairment		11.5			26.2			-
Other		(3.9	)		2.5			0.2
Total operating expenses		763.2			945.5			2,428.7
Operating income / (loss)		101.5			(71.4	)		(1,559.4	)
Other income / (expense), net
Investment income		0.9			1.4			2.5
Interest expense		(126.6	)		(124.0	)		(122.9	)
Charge for early redemption of debt		(30.9	)		(2.8	)		-
Other deductions		(1.5	)		(2.9	)		(2.3	)
Total other expense, net		(158.1	)		(128.3	)		(122.7	)
Earnings (loss) from operations before income tax		(56.6	)		(199.7	)		(1,682.1	)
Income tax expense		18.0			22.3			47.7
Net loss	$	(74.6	)	$	(222.0	)	$	(1,729.8	)
See Notes to Consolidated Financial Statements.

F-3

DPL INC.

STATEMENTS OF COMPREHENSIVE LOSS

	Year ended December 31,
$ in millions	2014			2013			2012
Net loss	$	(74.6	)	$	(222.0	)	$	(1,729.8	)
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax benefit / (expense) of $0.2, $0.6 and $(0.2) for each respective period		(0.3	)		(1.2	)		0.5
Reclassification to earnings, net of income tax benefit / (expense) of $(0.2), $(0.7) and $0.0 for each respective period		0.2			1.4			(0.1	)
Total change in fair value of available-for-sale securities		(0.1	)		0.2			0.4
Derivative activity:
Change in derivative fair value, net of income tax benefit / (expense) of $10.3, $(10.6) and $1.4 for each respective period		(19.0	)		19.7			(1.5	)
Reclassification to earnings, net of income tax benefit / (expense) of $(9.5), $(2.3) and $0.4 for each respective period		16.9			3.4			(0.5	)
Total change in fair value of derivatives		(2.1	)		23.1			(2.0	)
Pension and postretirement activity:
Net loss for the period, net of income tax benefit / (expense) of $8.3, $(2.7) and $1.0 for each respective period		(14.9	)		4.9			(1.9	)
Reclassification to earnings, net of income tax benefit / (expense) of $0.0, $0.3 and $0.0 for each respective period		-			0.3			-
Total change in unfunded pension and postretirement		(14.9	)		5.2			(1.9	)
Other comprehensive income / (loss)		(17.1	)		28.5			(3.5	)
Net comprehensive loss	$	(91.7	)	$	(193.5	)	$	(1,733.3	)
See Notes to Consolidated Financial Statements.

F-4

DPL INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended December 31,
$ in millions	2014			2013			2012
Cash flows from operating activities:
Net loss	$	(74.6	)	$	(222.0	)	$	(1,729.8	)
Adjustments to reconcile Net loss to Net cash from operating activities
Depreciation and amortization		139.8			132.9			125.4
Amortization of intangibles		1.2			7.1			95.1
Amortization of debt market value adjustments		0.3			(14.4	)		(19.0	)
Deferred income taxes		17.7			24.0			(4.2	)
Charge for early redemption of debt		30.9			2.8			-
Goodwill impairment		135.8			306.3			1,817.2
Fixed-asset impairment		11.5			26.2			-
Loss / (Gain) on asset disposal		(3.9	)		2.5			0.2
Recognition of deferred SECA revenue		-			-			(17.8	)
Changes in certain assets and liabilities:
Accounts receivable		0.5			7.4			13.4
Inventories		(24.9	)		27.4			15.6
Prepaid taxes		(0.9	)		0.7			-
Taxes applicable to subsequent years		(7.1	)		(1.4	)		7.2
Deferred regulatory costs, net		5.4			7.6			(1.1	)
Accounts payable		32.1			(5.8	)		(16.2	)
Accrued taxes payable		20.7			(5.5	)		5.1
Accrued interest payable		(1.3	)		(3.3	)		1.5
Other current and deferred liabilities		(40.6	)		1.5			(18.6	)
Pension, retiree and other benefits		19.1			1.8			28.5
Unamortized investment tax credit		(0.5	)		(0.5	)		(0.3	)
Insurance and claims costs		(0.2	)		(4.8	)		(2.8	)
Other		(16.9	)		12.3			(7.9	)
Net cash from operating activities		244.1			302.8			291.5
Cash flows from investing activities:
Capital expenditures		(118.1	)		(124.4	)		(198.1	)
Proceeds from sale of property		10.7			0.8			1.1
Insurance proceeds		0.3			7.6			-
Purchase of renewable energy credits		(3.5	)		(3.9	)		(5.4	)
Decrease / (increase) in restricted cash		(3.3	)		(2.8	)		2.9
Other investing activities, net		1.3			(1.2	)		0.3
Net cash from investing activities		(112.6	)		(123.9	)		(199.2	)

F-5

DPL INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

$ in millions	Year ended December 31, 2014			Year ended December 31, 2013			Year ended December 31, 2012
Cash flows from financing activities:
Deferred financing costs		(3.6	)		(15.3	)		(0.8	)
Retirement of debt		(335.0	)		(945.1	)		(0.1	)
Premium paid for early redemption of debt		(29.1	)		(2.4	)		-
Issuance of long-term debt		200.0			645.0			-
Borrowings from revolving credit facilities		190.0			50.0			-
Repayment of borrowings from revolving credit facilities		(190.0	)		(50.0	)		-
Dividends paid on common stock		-			-			(64.1	)
Contributions of additional paid-in capital from parent		-			-			0.3
Payment to former warrant holders		-			-			(9.0	)
Net cash from financing activities		(167.7	)		(317.8	)		(73.7	)
Cash and cash equivalents:
Net change		(36.2	)		(138.9	)		18.6
Balance at beginning of period		53.2			192.1			173.5
Cash and cash equivalents at end of period	$	17.0		$	53.2		$	192.1
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	117.3		$	137.5		$	136.9
Income taxes (refunded) / paid, net	$	0.7		$	(5.2	)	$	47.6
Non-cash financing and investing activities:
Accruals for capital expenditures	$	16.3		$	14.7		$	16.7
See Notes to Consolidated Financial Statements.

F-6

DPL INC.

CONSOLIDATED BALANCE SHEETS

$ in millions	December 31, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	17.0		$	53.2
Restricted cash		16.8			13.5
Accounts receivable, net (Note 2)		200.9			203.3
Inventories (Note 2)		100.2			82.7
Taxes applicable to subsequent years		77.8			70.6
Regulatory assets, current (Note 3)		44.2			20.8
Other prepayments and current assets		41.8			35.1
Total current assets		498.7			479.2
Property, plant and equipment:
Property, plant and equipment		2,759.3			2,677.0
Less: Accumulated depreciation and amortization		(318.4	)		(206.7	)
		2,440.9			2,470.3
Construction work in process		76.7			63.9
Total net property, plant and equipment		2,517.6			2,534.2
Other non-current assets:
Regulatory assets, non-current (Note 3)		167.5			159.7
Goodwill (Note 5)		317.0			452.8
Intangible assets, net of amortization (Note 5)		37.4			42.8
Other deferred assets		39.6			52.8
Total other non-current assets		561.5			708.1
Total Assets	$	3,577.8		$	3,721.5
See Notes to Consolidated Financial Statements.

F-7

DPL INC.

CONSOLIDATED BALANCE SHEETS

$ in millions	December 31, 2014			December 31, 2013
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Current portion - long-term debt (Note 6)	$	20.1		$	10.2
Accounts payable		109.2			78.2
Accrued taxes		102.6			89.4
Accrued interest		27.2			28.5
Customer security deposits		14.4			13.9
Regulatory liabilities, current (Note 3)		4.4			-
Insurance and claims costs		6.4			6.7
Other current liabilities		48.7			64.2
Total current liabilities		333.0			291.1
Non-current liabilities:
Long-term debt (Note 6)		2,139.6			2,284.2
Deferred taxes (Note 7)		587.3			564.3
Taxes payable		80.9			79.1
Regulatory liabilities, non-current (Note 3)		124.1			121.1
Pension, retiree and other benefits (Note 8)		95.9			51.6
Unamortized investment tax credit		2.2			2.8
Other deferred credits		48.2			69.4
Total non-current liabilities		3,078.2			3,172.5
Redeemable preferred stock of subsidiary (Note 11)		18.4			18.4
Commitments and contingencies (Note 13)
Common shareholder's equity:
Common stock:
1,500 shares authorized; 1 share issued and outstanding
at December 31, 2014 and 2013		-			-
Other paid-in capital		2,237.4			2,237.0
Accumulated other comprehensive income		7.5			24.6
Retained earnings / (deficit)		(2,096.7	)		(2,022.1	)
Total common shareholder's equity		148.2			239.5
Total Liabilities and Shareholder's Equity	$	3,577.8		$	3,721.5
See Notes to Consolidated Financial Statements.

F-8

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, 2012
Beginning balance		1		-		2,237.3			(0.4	)		(6.2	)		2,230.7
Total comprehensive income (loss)									(3.5	)		(1,729.8	)		(1,733.3	)
Common stock dividends (a)												(70.0	)		(70.0	)
Other						(0.6	)								(0.6	)
Ending balance		1		-		2,236.7			(3.9	)		(1,806.0	)		426.8
Year ended December 31, 2013
Total comprehensive income (loss)									28.5			(222.0	)		(193.5	)
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
Total comprehensive income (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
(a) 1,500 shares authorized
(b) $5.9 million of dividends declared in 2012 were reversed in 2013.
See Notes to Consolidated Financial Statements.

F-9

DPL Inc.

Notes to Consolidated Financial Statements

For the years ended December 31, 2014, 2013 and 2012

Note 1– Overview and Summary of Significant Accounting Policies

Description of Business

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’s two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary. See Note 14 for more information relating to these 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 retail service are still regulated. DP&L has the exclusive right to provide such service to its approximately 516,000 customers located in West Central Ohio. Additionally, DP&L procures and provides retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at five coal-fired power stations. Beginning in 2014, DP&L no longer supplies 100% of the generation for SSO customers and by January 2016, SSO will be 100% 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 sells 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. Comments and reply comments were filed. DP&L amended its application on February 25, 2014 and again on May 23, 2014. Additional comments and reply comments were filed. 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 a new unregulated affiliate of DPL or through a sale.

DPLER sells competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER’s operations include those of its wholly-owned subsidiary MC Squared. DPLER has approximately 260,000 customers currently located throughout Ohio and Illinois. Approximately 131,000 of DPLER’s customers are also electric distribution customers of DP&L. DPLER does not own any transmission or generation assets, and purchases 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.

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. All of DPL’s subsidiaries are wholly-owned.

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

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators 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.

F-10

DPL and its subsidiaries employed 1,182 people as of December 31, 2014, of which 1,130 were employed by DP&L. Approximately 61% 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 for more information.

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

All material intercompany accounts and transactions are eliminated in consolidation.

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; the valuation of goodwill; 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. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions; operating or regulatory environment; increased competitive environment; increase in fuel costs particularly when we are unable to pass its effect to customers; negative or declining cash flows; loss of a key contract or customer particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods. See Note 5 for information regarding the impairments of goodwill in 2014, 2013 and 2012.

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 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

F-11

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.

Sale of Receivables

DPLER and its subsidiary MC Squared sell receivables from their customers. These sales are at face value for cash at the billed amounts for their customers’ use of energy. Total receivables sold during the years ended December 31, 2014 and 2013 were $125.6 million and $96.1 million, respectively.

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 $1.5 million, $1.5 million and $4.0 million in the years ended December 31, 2014, 2013 and 2012, 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 – Changes in Estimates

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.

During the fourth quarter of 2013, the Company tested the recoverability of long-lived assets at certain generating stations. See Note 15 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.

For DPL’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 5.3% in 2014, 5.8% in 2013 and 4.8% in 2012.

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The following is a summary of DPL’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2014 and 2013:

	December 31,
$ in millions	2014		Composite Rate	2013		Composite Rate
Regulated:
Transmission	$	227.5	4.1%	$	213.1	4.1%
Distribution		1,011.7	5.4%		970.1	5.6%
General		62.5	12.4%		56.8	12.1%
Non-depreciable		61.6	N/A		60.8	N/A
Total regulated		1,363.3			1,300.8
Unregulated:
Production / Generation		1,354.9	5.4%		1,340.8	6.2%
Other		21.3	8.1%		15.7	8.9%
Non-depreciable		19.8	N/A		19.7	N/A
Total unregulated		1,396.0			1,376.2
Total property, plant and equipment in service	$	2,759.3	5.3%	$	2,677.0	5.8%

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 associated with the retirement of our long-lived assets consists 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, 2012	$	23.9
Calendar 2013
Accretion expense		0.8
Settlements		(0.3	)
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

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

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associated with these assets. We have recorded $119.3 million and $115.0 million in estimated costs of removal at December 31, 2014 and 2013, 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 for additional information.

Changes in the Liability for Transmission and Distribution Asset Removal Costs

$ in millions
Balance at December 31, 2012	$	112.1
Calendar 2013
Additions		22.0
Settlements		(19.1	)
Balance at December 31, 2013		115.0
Calendar 2014
Additions		19.6
Settlements		(15.3	)
Balance at December 31, 2014	$	119.3

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 DPL 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 for more information about Regulatory Assets and Liabilities.

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, renewable energy credits, customer relationships, customer contracts and trademark/trade name. 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.

Customer relationships recognized as part of the purchase accounting are amortized over nine to fifteen years and customer contracts are amortized over the average length of the contracts. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are amortized as they are used or retired. Trademark/trade name have an indefinite life and accordingly are not amortized. See Note 5 for additional information.

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Income Taxes

Income taxes are accounted in accordance with FASC 740, “Income Taxes”, which requires an asset and liability approach for financial accounting and reporting of income taxes with tax effects of differences, based on currently enacted income tax rates, between the financial reporting and tax basis of accounting reported as deferred tax assets or liabilities in the balance sheets. Valuation allowances are provided against deferred tax assets unless it is more likely than not that the asset will be realized.

Investment tax credits, which have been used to reduce federal income taxes payable, are deferred for financial reporting purposes and are amortized over the useful lives of the property to which they relate. For rate-regulated operations, additional deferred income taxes and offsetting regulatory assets or liabilities are recorded to recognize that income taxes will be recoverable or refundable through future revenues.

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 7 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 basis for public equity security and fixed maturity investments is 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, 2014, 2013 and 2012, were $50.8 million, $50.5 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 include restrictions imposed by agreements related to deposits held as collateral.

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 10 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

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maintains an active run-off policy for directors’ and officers’ liability and fiduciary through their expiration in 2017 and may or may not be renewed at that time. DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. In addition, DP&L has estimated liabilities for medical, life, and disability reserves for claims costs below certain coverage thresholds of third-party providers. We record these additional insurance and claims costs of approximately $15.6 million and $18.8 million at December 31, 2014 and 2013, 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 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.

Related Party Transactions

In December 2013, an agreement was signed, effective January 1, 2014, whereby 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. 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 non-regulated businesses.

The following table provides a summary of these transactions:

	For the year ended
	December 31,
$ in millions	2014		2013
Transactions with the Service Company
Charges for services provided	$	35.8	$	-
Charges to the Service Company	$	0.1	$	-

Transactions with the Service Company:	At December 31, 2014			At December 31, 2013
Net payable to the Service Company	$	(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 $0.4 million at December 31, 2014 and 2013, respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $14.9 million at December 31, 2014 and 2013, respectively that was established upon the Trust’s deconsolidation in 2003. See Note 6 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.

Recently Adopted Accounting Standards

Discontinued Operations

The FASB recently issued ASU 2014-08 “Presentation of Financial Statements” (Topic 205) and “Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an

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Entity” effective for annual and interim periods beginning after December 15, 2014. ASU 2014-08 updates the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results. In addition, an entity is required to expand disclosures for discontinued operations by providing more information about the assets, liabilities, revenues and expenses of discontinued operations both on the face of the financial statements and in the Notes. For the disposal of an individually significant component of an entity that does not qualify for discontinued operations reporting, an entity is required to disclose the pretax profit or loss of the component in the Notes. Our early adoption of ASU No. 2014-008 in the third quarter of 2014 did not have any impact on our overall results of operations, financial position or cash flows.

Recently Issued Accounting Standards

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.

Revenue from Contracts with Customers

The FASB recently issued ASU 2014-09 “Revenue from Contracts with Customers” (Topic 606) effective for annual and interim periods beginning after December 15, 2016; with retrospective application. The core principle of the ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Because the guidance in this update is principles-based, it can be applied to all contracts with customers regardless of industry-specific or transaction-specific fact patterns. Additionally, the guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. We have not yet determined the extent, if any, to which our overall results of operations, financial position or cash flows may be affected by the implementation of this ASU.

Note 2 – Supplemental Financial Information

	December 31,
$ in millions	2014			2013
Accounts receivable, net
Unbilled revenue	$	79.2		$	77.8
Customer receivables		104.8			102.7
Amounts due from partners in jointly-owned stations		14.2			15.8
Other		4.0			8.2
Provisions for uncollectible accounts		(1.3	)		(1.2	)
Total accounts receivable, net	$	200.9		$	203.3
Inventories
Fuel and limestone	$	65.3		$	42.7
Plant materials and supplies		33.5			38.2
Other		1.4			1.8
Total inventories, at average cost	$	100.2		$	82.7

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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, 2014, 2013 and 2012 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		2014		2013		2012
Gains and losses on Available-for-sale securities activity (Note 9):
	Other income / (deductions)	$	0.4	$	2.1	$	(0.1)
	Total before income taxes		0.4		2.1		(0.1)
	Tax expense		(0.2)		(0.7)		-
	Net of income taxes		0.2		1.4		(0.1)
Gains and losses on cash flow hedges (Note 10):
	Interest Expense		(1.3)		-		0.2
	Revenue		28.4		2.2		(0.1)
	Purchased power		(0.7)		3.5		(1.1)
	Total before income taxes		26.4		5.7		(1.0)
	Tax expense		(9.5)		(2.3)		0.5
	Net of income taxes		16.9		3.4		(0.5)
Amortization of defined benefit pension items (Note 8):
	Tax benefit		-		0.3		-
	Net of income taxes		-		0.3		-
Total reclassifications for the period, net of income taxes		$	17.1	$	5.1	$	(0.6)

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The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2014 and 2013 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities			Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total
Balance January 1, 2013	$	0.4		$	(2.5	)	$	(1.8	)	$	(3.9	)
Other comprehensive income / (loss) before reclassifications		(1.2	)		19.7			4.9			23.4
Amounts reclassified from accumulated other comprehensive income / (loss)		1.4			3.4			0.3			5.1
Net current period other comprehensive income		0.2			23.1			5.2			28.5
Balance 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 December 31, 2014	$	0.5		$	18.5		$	(11.5	)	$	7.5

Note 3 – Regulatory Matters

In accordance with FASC 980, we have recognized total regulatory assets of $211.7 million and $180.5 million as of December 31, 2014 and 2013 and total regulatory liabilities of $128.5 million and $121.1 million as of December 31, 2014 and 2013. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 1 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 (a)	Amortization Through	2014		2013
Regulatory assets, current:
Deferred storm costs	A	2015	$	22.3	$	-
Fuel and purchased power recovery costs	B	2015		16.3		6.3
Economic development costs	B	2015		2.1		7.7
Energy efficiency program	B	2015		1.8		-
Transmission costs	B	2015		-		2.6
Other miscellaneous	B	2015		1.7		4.2
Total regulatory assets, current			$	44.2	$	20.8
Regulatory assets, non-current:
Pension benefits	A	Ongoing	$	99.6	$	77.1
Deferred recoverable income taxes	A/C	Ongoing		43.1		32.4
Unamortized loss on reacquired debt	A	Various		9.9		10.9
CCEM smart grid and advanced metering infrastructure costs	D	Undetermined		6.6		6.6
Retail settlement system costs	D	Undetermined		3.1		3.1
Consumer education campaign	D	Undetermined		3.0		3.0
Deferred storm costs	D	2015		-		25.6
Other miscellaneous	D	Undetermined		2.2		1.0
Total regulatory assets, non-current			$	167.5	$	159.7
Regulatory liabilities, current:
Transmission costs			$	2.9	$	-
Other miscellaneous				1.5		-
Total regulatory liabilities, current			$	4.4	$	-
Regulatory liabilities, non-current:
Estimated costs of removal - regulated property			$	119.3	$	115.0
Postretirement benefits				4.8		5.6
Other miscellaneous				-		0.5
Total regulatory liabilities, non-current			$	124.1	$	121.1

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.

Regulatory Assets

Deferred storm costs represent costs incurred to repair the damage to DP&L’s distribution equipment by major storms in 2008, 2011 and 2012. Such costs are included in “Regulatory Assets, non-current” on the accompanying Consolidated Balance Sheets as of December 31, 2013 and in “Regulatory Assets, current” as of December 31, 2014. DP&L filed an application with the PUCO in 2012 to recover these costs. On April 14, 2014, DP&L reached an agreement in principle whereby DP&L would recover storm costs of $22.3 million from all customers on a non-bypassable basis. As a result, using the best estimate of the amount that is probable of recovery, DP&L reduced the regulatory asset balance to $22.3 million. In accordance with FASC 980 “Regulated Operations”, the reduction was recognized as a current period expense, which is included in Operation and maintenance and the corresponding adjustment to carrying costs which is included in interest expense on the accompanying Statements of Operations. In

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accordance with the agreement reached with the PUCO staff, a Stipulation was filed and a final order was issued on December 17, 2014 that approved the Stipulation covering this agreement in principle. Recovery will begin in January 2015 therefore this asset was reclassified to current.

Fuel and purchased power recovery costs represent 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. An audit of 2012 fuel costs occurred in 2013, and on June 12, 2013 we received a report from the auditor recommending a pre-tax disallowance of $5.3 million. A reserve of $2.6 million was recorded against the regulatory asset. In August 2014, the PUCO issued an order, which overruled the auditor recommendation and instead included the disallowance of an immaterial amount of fuel costs. The impact of the order was a reversal in the third quarter of 2014 of the vast majority of the previously established $2.6 million reserve and a corresponding reduction to fuel expense. The 2013 audit was completed with no material disallowance of fuel expenses. The costs recovered through the fuel rider decrease each year as more SSO supply is provided through the competitive bid. The fuel rider will be completely phased out beginning January 1, 2016.

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.

Energy efficiency program costs represent 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.

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.

Pension benefits represent 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.

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

CCEM smart grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and 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. We plan to file to recover these deferred costs in a future regulatory rate proceeding. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates.

Retail settlement system costs represent costs to implement a retail settlement system that reconciles the energy a CRES supplier delivers to its customers with what its customers actually use. Based on case precedent in other utilities’ cases, the costs are recoverable through a future DP&L rate proceeding.

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Consumer education campaign represents costs for consumer education advertising regarding electric deregulation. DP&L will be seeking recovery of these costs as part of our next distribution rate case filing at the PUCO. The timing of such a filing has not yet been determined.

Regulatory Liabilities

Transmission Costs see “Regulatory Assets – Transmission costs” above.

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.

Note 4 – Ownership of Coal-fired Facilities

DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. As of December 31, 2014, DP&L had $25.0 million of construction work in process at such facilities. DP&L’s share of the operating cost 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.

DP&L’s undivided ownership interest in such facilities at December 31, 2014, 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)		SCR and FGD Equipment Installed and in Service (Yes/No)
Jointly-owned production units
Conesville - Unit 4		16.5		129	$	24	$	2	$	1	Yes
Killen - Unit 2		67.0		402		308		19		2	Yes
Miami Fort - Units 7 and 8		36.0		368		214		23		2	Yes
Stuart - Units 1 through 4		35.0		808		219		16		14	Yes
Zimmer -  Unit 1		28.1		371		182		35		6	Yes
Transmission (at varying percentages)						42		6		-
Total				2,078	$	989	$	101	$	25

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.

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Note 5 – Goodwill and Other Intangible Assets

Impairment of Goodwill

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 includes 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 represents the value assigned at the Merger date, as adjusted for subsequent changes in the purchase price allocation, less recognized impairments.

During the first quarter of 2014, we performed an interim impairment test on the $135.8 million in goodwill at our DPLER reporting unit. The DPLER reporting unit was identified as being "at risk" during the fourth quarter of 2013. The impairment indicators arose based on market information available regarding actual and proposed sales of competitive retail marketers, which indicated a significant decline in valuations during the first quarter of 2014. In Step 1 of the interim impairment test, the fair value of the reporting unit was determined to be less than its carrying amount under both the market approach and the income approach using a discounted cash flow valuation model. The significant assumptions included commodity price curves, estimated electricity to be demanded by its customers, changes in its customer base through attrition and expansion, discount rates, the assumed tax structure and the level of working capital required to run the business. 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.

As of October 1, 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 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.

DPL recognized a goodwill impairment expense of $1.817.2 million in 2012 at the DP&L reporting unit. During 2012, North American natural gas prices fell significantly compared to the previous year, which exerted downward pressure on wholesale power prices in the Ohio power market. These falling power prices compressed wholesale margins at DP&L and led to increased customer switching from DP&L to other CRES providers, including DPLER, who were offering retail prices lower than DP&L’s standard service offer. In addition, several municipalities in DP&L’s service territory passed ordinances allowing them to become government aggregators and contracted with CRES providers to provide generation service to the customers located within the municipal boundaries, further contributing to the switching trend. CRES providers also became more active in DP&L’s service territory. These developments reduced DP&L’s forecasted profitability, operating cash flows and liquidity. As a result, in September 2012, management lowered its previous forecasts of profitability and operating cash flows. Collectively, these events were considered an interim goodwill impairment indicator at the DP&L reporting unit. There were no interim impairment indicators identified for the goodwill at DPLER in 2012.

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. The Company’s effective tax rates were impacted by the pretax impairment, however. The Company’s effective tax rates were (31.8%), (11.2%) and (2.8%) for the years ended December 31, 2014, 2013 and 2012, respectively.

F-23

The following table summarizes the changes in Goodwill:

$ in millions	DP&L Reporting Unit			DPLER Reporting Unit			Total
Balance at December 31, 2012
Goodwill	$	2,440.5		$	135.8		$	2,576.3
Accumulated impairment losses		(1,817.2	)		-			(1,817.2	)
Net balance at December 31, 2012	$	623.3		$	135.8		$	759.1
Goodwill impairments during 2013	$	(306.3	)	$	-		$	(306.3	)
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

The following tables summarize the balances comprising intangible assets as of December 31, 2014:

$ in millions	December 31, 2014							December 31, 2013
	Gross Balance		Accumulated Amortization			Net Balance		Gross Balance		Accumulated Amortization			Net Balance
Subject to Amortization
Customer Contracts (a)	$	27.0	$	(27.0	)	$	-	$	27.0	$	(25.8	)	$	1.2
Customer Relationships (b)		31.8		(6.9	)		24.9		31.8		(4.6	)		27.2
Other (c)		7.7		(1.3	)		6.4		8.4		(0.1	)		8.3
		66.5		(35.2	)		31.3		67.2		(30.5	)		36.7
Not subject to Amortization
Trademark/Trade name (d)		6.1		-			6.1		6.1		-			6.1
Total intangibles	$	72.6	$	(35.2	)	$	37.4	$	73.3	$	(30.5	)	$	42.8

(a) Represents above market contracts that DPLER has with third-party customers existing as of the Merger date.

(b) Represents relationships DPLER has with third-party customers as of the Merger date, where DPLER has regular contact with the customer, and the customer has the ability to make direct contact with DPLER.

(c) Consists of various intangible assets including renewable energy credits, emission allowances, and other intangibles, none of which are individually significant.

(d) Trademark/Trade name represents the value assigned to the trade names of DPLER and MC Squared.

F-24

The following table summarizes, by category, intangible assets acquired during the period ended December 31, 2014:

$ in millions	Amount		Subject to Amortization/ Indefinite-lived	Weighted Average Amortization Period (years)	Amortization Method
Renewable Energy Certificates	$	7.7	Subject to amortization	Various	As Utilized

The following table summarizes the amortization expense, broken down by intangible asset category for 2015 through 2019:

	Estimated amortization expense
	Years ending December 31,
$ in millions	2015		2016		2017		2018		2019
Customer relationships	$	3.8	$	3.1	$	2.7	$	2.3	$	2.1
Renewable Energy Certificates		4.2		3.5		-		-		-
	$	8.0	$	6.6	$	2.7	$	2.3	$	2.1

Note 6 – Debt Obligations

Long-term debt
$ in millions	December 31, 2014			December 31, 2013
First mortgage bonds due in September 2016 - 1.875%	$	445.0		$	445.0
Pollution control series due in January 2028 - 4.7%		35.3			35.3
Pollution control series due in January 2034 - 4.8%		179.1			179.1
Pollution control series due in September 2036 - 4.8%		100.0			100.0
Pollution control series due in November 2040 - variable rates: 0.04% - 0.15% and 0.04% - 0.26% (a)		100.0			100.0
U.S. Government note due in February 2061 - 4.2%		18.1			18.3
Unamortized debt discount		(2.8	)		(3.1	)
Total long-term debt at subsidiary		874.7			874.6
Bank term loan due in May 2018 - variable rates: 2.41% - 2.42% (a)		140.0			180.0
Senior unsecured bonds due in October 2016 - 6.50%		130.0			430.0
Senior unsecured bonds due in October 2019 - 6.75%		200.0			-
Senior unsecured bonds due in October 2021 - 7.25%		780.0			780.0
Note to DPL Capital Trust II due in September 2031 - 8.125%		15.6			20.6
Unamortized debt discount		(0.7	)		(1.0	)
Total long-term debt	$	2,139.6		$	2,284.2
(a) - range of interest rates for the twelve months ended December 31, 2014 and December 31, 2013, respectively

F-25

Current portion - long-term debt
$ in millions	December 31, 2014		December 31, 2013
Bank term loan due in May 2018 - variable rates: 2.41% - 2.42% (a)	$	20.0	$	10.0
U.S. Government note due in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		-		0.1
Total current portion - long-term debt	$	20.1	$	10.2
(a) - range of interest rates for the twelve months ended December 31, 2014 and December 31, 2013, respectively

At December 31, 2014, maturities of long-term debt are summarized as follows:

Due within the twelve months ending December 31,
$ in millions
2015	$	20.1
2016		615.1
2017		40.1
2018		60.1
2019		200.1
Thereafter		1,227.7
		2,163.2
Unamortized discounts and premiums, net		(3.5	)
Total long-term debt	$	2,159.7

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

On December 4, 2008, the OAQDA issued $100.0 million of collateralized, variable rate Revenue Refunding Bonds Series A and B due November 1, 2040. In turn, DP&L borrowed these funds from the OAQDA and issued corresponding first mortgage bonds to support repayment of the funds. The payment of principal and interest on each series of the bonds when due is backed by a standby letter of credit issued by JPMorgan Chase Bank, N.A. This letter of credit facility, which expires in June 2018, is irrevocable and has no subjective acceleration clauses. Fees associated with this letter of credit facility were not material during the years ended December 31, 2014, 2013 and 2012.

On May 10, 2013, DP&L entered into a $300.0 million unsecured revolving credit agreement with a syndicated bank group. This $300.0 million facility has a five year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature which provides DP&L the ability to increase the size of the facility by an additional $100.0 million. At December 31, 2014, there were two letters of credit in the amount of $0.7 million outstanding, with the remaining $299.3 million available to DP&L. Fees associated with this revolving credit facility were not material during the years ended December 31, 2014 or 2013.

DP&L’s unsecured revolving credit agreement and DP&L’s amended standby letters of credit have two financial covenants, the first being Total Debt to Total Capitalization and the second being 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.

On March 1, 2011, DP&L completed the purchase of $18.7 million of electric transmission and distribution assets from the federal government that are located at the Wright-Patterson Air Force Base (WPAFB). DP&L financed the acquisition of these assets with a note payable to the federal government that is payable monthly over 50 years and bears interest at 4.2% per annum.

F-26

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.

On May 10, 2013, DPL entered into a $200.0 million unsecured term loan agreement. This term loan has a five year term expiring on May 10, 2018; however, if DPL has not either: (a) prepaid the full $200.0 million term loan balance; or (b) refinanced its senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this DPL term loan shall be July 15, 2016. This term loan amortizes at 5% of the original balance per quarter from September 2014 to maturity. As of December 31, 2014 there was $160 million outstanding on this Term Loan. Fees associated with this new term loan were not material during the years ended December 31, 2014 or 2013.

On May 10, 2013, DPL entered into a $100.0 million unsecured revolving credit facility. This facility has a $100.0 million letter of credit sublimit and a feature which provides DPL the ability to increase the size of the facility by an additional $50.0 million. This facility has a five year term expiring on May 10, 2018; however, if DPL has not refinanced its senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this DPL credit facility shall be July 15, 2016. As of December 31, 2014 there was one letter of credit issued in the amount of $2.3 million, with the remaining $97.7 million available to DPL. Fees associated with this revolving credit facility were not material during the years ended December 31, 2014 or 2013.

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

DPL’s unsecured revolving credit agreement and unsecured term loan restrict dividend payments from DPL to AES and adjust the cost of borrowing under the facilities under certain credit rating scenarios.

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 million of the first tranche of five year senior unsecured notes issued with a 6.50% coupon and $20 million of the second tranche of ten year senior unsecured notes issued with a 7.25% coupon. Subsequent to repurchasing these bonds DPL immediately retired them.

On September 6, 2014, DPL announced its intent to purchase a maximum of $280.0 million of aggregate principal of the Senior Unsecured bonds maturing October 2016 through a tender offer. On October 6, 2014, DPL increased the maximum amount of the tender to $300.0 million and on October 20th the tender expired. DPL settled the $300.0 million on October 6th through (a) net proceeds from a $200.0 million Senior Unsecured note issuance (maturing October 2019 and priced at 6.75%); (b) a draw on the DPL revolving line of credit and (c) cash on hand.

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.

F-27

Note 7 – Income Taxes

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

	Years ended December 31,
$ in millions	2014			2013			2012
Computation of tax expense
Federal income tax expense / (benefit)(a)	$	(19.8	)	$	(69.9	)	$	(588.7	)
Increases (decreases) in tax resulting from:
State income taxes, net of federal effect		1.2			1.7			3.5
Depreciation of AFUDC - Equity		(3.4	)		(3.2	)		(2.4	)
Investment tax credit amortized		(0.5	)		(0.5	)		(0.3	)
Section 199 - domestic production deduction		(1.1	)		(4.1	)		(2.1	)
Non-deductible merger-related compensation		-			-			0.6
Non-deductible goodwill impairment		47.5			107.2			636.0
Accrual (settlement) for open tax years		(6.6	)		(8.8	)		(0.1	)
Other, net (b)		0.7			(0.1	)		1.2
Total tax expense	$	18.0		$	22.3		$	47.7
Components of tax expense
Federal - current	$	(0.1	)	$	1.8		$	48.6
State and Local - current		0.9			0.7			1.2
Total current		0.8			2.5			49.8
Federal - deferred		16.6			18.1			(4.9	)
State and local - deferred		0.6			1.7			2.8
Total deferred		17.2			19.8			(2.1	)
Total tax expense	$	18.0		$	22.3		$	47.7

F-28

Components of Deferred Tax Assets and Liabilities
	December 31,
$ in millions	2014			2013
Net non-current Assets / (Liabilities)
Depreciation / property basis	$	(548.2	)	$	(531.5	)
Income taxes recoverable		(14.8	)		(11.4	)
Regulatory assets		(18.0	)		(15.6	)
Investment tax credit		1.5			1.0
Compensation and employee benefits		3.2			(3.9	)
Intangibles		(7.0	)		(2.0	)
Long-term debt		(1.5	)		(1.7	)
Other (c)		(2.5	)		0.8
Net non-current liabilities	$	(587.3	)	$	(564.3	)
Net current Assets / (Liabilities) (d)
Other	$	1.1		$	(2.6	)
Net current assets / (liabilities)	$	1.1		$	(2.6	)

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

(b) Includes expense of $0.4 million, $0.0 million and benefits of $1.2 million in the years ended December 31, 2014 2013, and 2012, respectively, of income tax related to adjustments from prior years.

(c) The Other non-current liabilities caption includes deferred tax assets of $27.1 million in 2014 and $20.7 million in 2013 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $21.9 million in 2014 and $16.6 million in 2013. These net operating loss carryforwards expire from 2014 to 2027.

(d) Amounts are included within Other prepayments and current assets and Other current liabilities on the Consolidated Balance Sheets of DPL.

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	2014			2013		2012
Tax expense / (benefit)	$	(9.1	)	$	15.4	$	(2.5	)

Accounting for Uncertainty in Income Taxes

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, 2012	$	18.3
Calendar 2013
Tax positions taken during prior period		(0.1	)
Lapse of Statute of Limitations		(6.9	)
Settlement with taxing authorities		(2.5	)
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

Of the December 31, 2014 balance of unrecognized tax benefits, $0.9 million is due to uncertainty in the timing of deductibility.

F-29

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, 2014, 2013 and 2012.

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 statutes 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.

Note 8 – Pension and Postretirement Benefits

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. In December 2013, an agreement was signed, effective January 1, 2014, whereby 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 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. There were no contributions during the years ended December 31, 2014, 2013 and 2012.

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.

F-30

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.

The following tables set forth the changes in our pension and postemployment benefit plans’ obligations and assets recorded on the balance sheets as of December 31, 2014 and 2013. The amounts presented in the following tables for pension 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 include both health and life insurance benefits.

$ in millions	Pension
	Year ended December 31, 2014			Year ended December 31, 2013
Change in benefit obligation
Benefit obligation at beginning of period	$	370.5		$	395.6
Service cost		5.9			7.2
Interest cost		17.5			15.6
Plan amendments		6.8			-
Actuarial (gain) / loss		67.3			(26.5	)
Benefits paid		(24.2	)		(21.4	)
Benefit obligation at end of period		443.8			370.5
Change in plan assets
Fair value of plan assets at beginning of period		349.1			361.4
Actual return on plan assets		46.4			8.7
Contributions to plan assets		0.4			0.4
Benefits paid		(24.2	)		(21.4	)
Fair value of plan assets at end of period		371.7			349.1
Funded status of plan	$	(72.1	)	$	(21.4	)

$ in millions	Postretirement
	Year ended December 31, 2014			Year ended December 31, 2013
Change in benefit obligation
Benefit obligation at beginning of period	$	19.7		$	22.4
Service cost		0.2			0.2
Interest cost		0.8			0.8
Actuarial (gain) / loss		0.2			(2.2	)
Benefits paid		(1.3	)		(1.5	)
Benefit obligation at end of period		19.6			19.7
Change in plan assets
Fair value of plan assets at beginning of period		3.7			4.2
Contributions to plan assets		0.9			1.0
Benefits paid		(1.3	)		(1.5	)
Fair value of plan assets at end of period		3.3			3.7
Funded status of plan	$	(16.3	)	$	(16.0	)

F-31

$ in millions	Pension						Postretirement
	December 31,						December 31,
	2014			2013			2014			2013
Amounts recognized in the Balance sheets
Current liabilities	$	(0.4	)	$	(0.4	)	$	(0.5	)	$	(0.5	)
Non-current liabilities		(71.7	)		(21.0	)		(15.8	)		(15.5	)
Net liability at Year ended December 31,	$	(72.1	)	$	(21.4	)	$	(16.3	)	$	(16.0	)
Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
Components:
Prior service cost	$	14.1		$	8.8		$	0.4		$	0.5
Net actuarial loss / (gain)		103.4			63.0			(5.0	)		(6.0	)
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax	$	117.5		$	71.8		$	(4.6	)	$	(5.5	)
Recorded as:
Regulatory asset	$	99.0		$	76.3		$	0.4		$	0.4
Regulatory liability		-			-			(4.8	)		(5.6	)
Accumulated other comprehensive income		18.5			(4.5	)		(0.2	)		(0.3	)
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax	$	117.5		$	71.8		$	(4.6	)	$	(5.5	)

The accumulated benefit obligation for our defined benefit pension plans was $431.0 million and $359.8 million at December 31, 2014 and 2013, respectively.

The net periodic benefit cost (income) of the pension and postemployment benefit plans were:

Net Periodic Benefit Cost - Pension
$ in millions	Year ended December 31, 2014			Year ended December 31, 2013			Year ended December 31, 2012
Service cost	$	5.9		$	7.2		$	6.2
Interest cost		17.5			15.6			17.3
Expected return on assets (a)		(22.9	)		(23.3	)		(22.7	)
Amortization of unrecognized:
Actuarial gain		3.4			4.9			5.0
Prior service cost		1.5			1.5			1.5
Net periodic benefit cost	$	5.4		$	5.9		$	7.3

F-32

Net Periodic Benefit Cost - Postretirement
$ in millions	Year ended December 31, 2014			Year ended December 31, 2013			Year ended December 31, 2012
Service cost	$	0.2		$	0.2		$	0.1
Interest cost		0.8			0.8			0.9
Expected return on assets (a)		(0.2	)		(0.1	)		(0.3	)
Amortization of unrecognized:
Actuarial loss		(0.6	)		(0.5	)		(0.6	)
Net periodic benefit cost	$	0.2		$	0.4		$	0.1

(a) For purposes of calculating the expected return on pension plan assets under GAAP, the market-related value of assets (MRVA) is used. GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be amortized into the MRVA equally over a period not to exceed five years. We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period. The MRVA used in the calculation of expected return on pension plan assets was approximately $361.0 million in 2014, $351.2 million in 2013, and $346.0 million in 2012.

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

Pension
$ in millions	Year ended December 31, 2014			Year ended December 31, 2013			Year ended December 31, 2012
Net actuarial loss / (gain)	$	43.8		$	(12.0	)	$	5.5
Prior service cost		6.8			-			-
Reversal of amortization item:
Net actuarial loss		(3.4	)		(4.9	)		(5.0	)
Prior service cost		(1.5	)		(1.5	)		(1.5	)
Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	45.7		$	(18.4	)	$	(1.0	)
Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	51.1		$	(12.5	)	$	6.3

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Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities (cont.)

Postretirement
$ in millions	Year ended December 31, 2014		Year ended December 31, 2013			Year ended December 31, 2012
Net actuarial loss / (gain)	$	0.4	$	(2.0	)	$	1.0
Reversal of amortization item:
Net actuarial gain		0.6		0.5			0.7
Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	1.0	$	(1.5	)	$	1.7
Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	1.2	$	(1.1	)	$	-

Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2015 are:

$ in millions	Pension		Postretirement
Net actuarial gain / (loss)	$	5.8	$	(0.5	)
Prior service cost	$	2.0	$	-

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.

For 2015, we are decreasing our expected long-term rate of return assumption to 6.50% from 6.75% for pension plan assets. In addition, we are decreasing our long-term rate of return assumption from to 4.50% from 6.00% for other postemployment benefit plan assets. These rates of return represent our long-term assumptions based on our current portfolio mixes. Also, for 2015, we have decreased our assumed discount rate to 4.02% from 4.86% for pension and to 3.71% from 4.58% for postemployment benefits expense to reflect current duration-based yield curve discount rates. A one percent change in the rate of return assumption for pension would result in an increase or decrease to the 2015 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 $0.5 million to 2015 pension expense. A 25 basis point decrease in the discount rate for pension would result in an increase of approximately $0.8 million to 2015 pension expense.

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, 2014. 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.

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The weighted average assumptions used to determine benefit obligations at December 31, 2014, 2013 and 2012 were:

Benefit Obligation Assumptions	Pension			Postretirement
	2014	2013	2012	2014	2013	2012
Discount rate for obligations	4.02%	4.86%	4.04%	3.71%	4.58%	3.75%
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, 2014, 2013 and 2012 were:

Net Periodic Benefit Cost / (Income) Assumptions	Pension			Postretirement
	2014	2013	2012	2014	2013	2012
Discount rate	4.86%	4.04%	4.88%	4.51%	4.58%	4.62%
Expected rate of return on plan assets	6.75%	6.75%	7.00%	6.00%	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, 2014, 2013 and 2012 are as follows:

Health Care Cost Assumptions	Expense			Benefit Obligation
	2014	2013	2012	2014	2013	2012
Pre - age 65
Current health care cost trend rate	7.75%	8.00%	8.50%	6.97%	7.75%	8.00%
Year trend reaches ultimate	2023	2019	2019	2029	2023	2019
Post - age 65
Current health care cost trend rate	6.75%	7.50%	8.00%	6.97%	6.75%	7.50%
Year trend reaches ultimate	2021	2018	2018	2029	2021	2018
Ultimate health care cost trend rate	5.00%	5.00%	5.00%	4.50%	5.00%	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	$	1.0	$	(0.9	)

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
2015	$	24.8	$	1.9
2016	$	25.2	$	1.8
2017	$	25.7	$	1.7
2018	$	26.3	$	1.6
2019	$	26.7	$	1.5
2020 - 2024	$	137.0	$	6.1

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We expect to make contributions of $0.4 million to our SERP in 2015 to cover benefit payments. We also expect to contribute $1.9 million to our other postemployment benefit plans in 2015 to cover benefit payments. We do not expect to make any contributions to our pension plan during 2015.

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 2014 plan year, the funded status of our defined benefit pension plan as calculated under the requirements of the Act was 113.86% and is estimated to be 113.86% until the 2015 status is certified in September 2015 for the 2015 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.

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.

Long-term strategic asset allocation guidelines are determined by management and take into account the Plan’s long-term objectives as well as its short-term constraints. The target allocations for plan assets are 2 – 41% for equity securities, 60 – 82% for fixed income securities and 8 – 16% for other investments. 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. Other investments include hedge funds that follow several different strategies.

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 the Company’s target pension plan allocation for 2014:

	Target
	Allocation
Equity Securities	19%
Debt Securities	69%
Real Estate	6%
Other	6%

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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.

(b) This category includes investments in investment-grade fixed-income instruments that are designed to mirror the term of the pension assets and generally have a tenor between 10 and 30 years.

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

(d) This category represents a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies.

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The fair values of our pension plan assets at December 31, 2013 by asset category are as follows:

Fair Value Measurements for Pension Plan Assets at December 31, 2013
Asset Category $ in millions	Market Value at December 31, 2013		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	$	10.5	$	10.5	$	-	$	-
Large cap equity		20.8		20.8		-		-
International equity		20.3		20.3		-		-
Emerging markets equity		3.2		3.2		-		-
SIIT dynamic equity		10.5		10.5		-		-
Total equity securities		65.3		65.3		-		-
Debt securities (b)
Emerging markets debt		6.6		6.6		-		-
High yield bond		6.9		6.9		-		-
Long duration fund		223.3		223.3		-		-
Total debt securities		236.8		236.8		-		-
Cash and cash equivalents (c)
Cash		0.9		0.9		-		-
Other investments (d)
Core property collective fund		23.5		-		23.5		-
Common collective fund		22.6		-		22.6		-
Total other investments		46.1		-		46.1		-
Total pension plan assets	$	349.1	$	303.0	$	46.1	$	-

(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.

(b) This category includes investments in investment-grade fixed-income instruments that are designed to mirror the term of the pension assets and generally have a tenor between 10 and 30 years.

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

(d) This category represents a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies.

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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 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)	$	3.2	$	3.2	$	-	$	-

(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, 2013 by asset category are as follows:

Fair Value Measurements for Postemployment Benefit Plan Assets at December 31, 2013
Asset Category $ in millions	Market Value at December 31, 2013		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)	$	3.7	$	3.7	$	-	$	-

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

Note 9 – Fair Value Measurements

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, 2014 and 2013. See Note 10 for the fair values of our derivative instruments.

	December 31, 2014				December 31, 2013
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.1	$	0.1	$	0.3	$	0.3
Equity securities		2.7		3.7		3.3		4.4
Debt securities		4.7		4.7		5.4		5.5
Hedge Funds		0.8		0.8		0.9		0.9
Real Estate		0.4		0.4		0.4		0.4
Total assets	$	8.7	$	9.7	$	10.3	$	11.5
Liabilities
Debt	$	2,159.7	$	2,204.8	$	2,294.4	$	2,334.6

Debt

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

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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.

DPL had $0.8 million ($0.5 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2014 and $0.9 million ($0.6 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2013.

Various investments were sold during the past twelve months to facilitate the distribution of benefits. During the past twelve months, $0.4 million ($0.2 million after tax) of unrealized gains were reversed into earnings. Over the next twelve months, $0.4 million ($0.2 million after tax) of unrealized gains are expected to be reversed to earnings.

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);

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, 2014 and 2013.

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The fair value of assets and liabilities at December 31, 2014 measured on a recurring basis 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.

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The fair value of assets and liabilities at December 31, 2013 measured on a recurring basis 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, 2013 (a)		Based on Quoted Prices in Active Markets		Other observable inputs		Unobservable inputs
Assets
Master trust assets
Money market funds	$	0.3	$	0.3	$	-	$	-
Equity securities		4.4		4.4		-		-
Debt securities		5.5		5.5		-		-
Hedge Funds		0.9		-		0.9		-
Real Estate		0.4		0.4		-		-
Total Master trust assets		11.5		10.6		0.9		-
Derivative assets
FTRs		0.2		-		-		0.2
Heating oil futures		0.2		0.2		-		-
Forward power contracts		13.4		-		13.4		-
Total derivative assets		13.8		0.2		13.4		0.2
Total assets	$	25.3	$	10.8	$	14.3	$	0.2
Liabilities
Forward power contracts	$	10.6	$	-	$	10.6	$	-
Total derivative liabilities		10.6		-		10.6		-
Long-term debt		2,334.6		-		2,316.1		18.5
Total liabilities	$	2,345.2	$	-	$	2,326.7	$	18.5

(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 and forward NYMEX-quality coal 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; and interest rate hedges, which use observable inputs to populate a pricing model.

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

F-42

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 97% 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. In 2014, AROs for asbestos, landfills, and river structures decreased by $1.5 million ($1.0 million after tax) primarily due to the sale of a generation plant. The ARO for ash ponds was increased by $2.4 million ($1.6 million after tax) due to new rules issued by the USEPA in December 2014 that will be effective in June 2015. The December 2014 increase of the AROs for ash ponds was limited to the ponds located at plants which are no longer in operation. Additional ash pond AROs will be recorded in the first quarter of 2015 for the ponds located at plants which remain in operation. There were no additions to our AROs during the year ended December 31, 2013.

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, 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 for further information

(b) See Note 5 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, 2014:

$ in millions		Fair Value	Valuation Technique	Unobservable input	Range (Weighted Average)
Long-lived assets held and used:
DP&L  (East Bend)	$	-	Discounted cash flows	Annual revenue growth	-31% to 18% (0%)
				Annual pretax operating margin	3% to 34% (15%)

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Note 10 – 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 or not designated as hedges for accounting purposes, which we refer to as mark to market.

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	Mark to Market	MWh		10.5		-			10.5
Heating Oil Futures	Mark to Market	Gallons		378.0		-			378.0
Natural Gas Futures	Mark to Market	Dths		200.0		-			200.0
Forward Power Contracts	Cash Flow Hedge	MWh		175.0		(2,991.0	)		(2,816.0	)
Forward Power Contracts	Mark to Market	MWh		1,725.2		(2,707.8	)		(982.6	)

At December 31, 2013, DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Mark to Market	MWh		7.1		-			7.1
Heating Oil Futures	Mark to Market	Gallons		1,428.0		-			1,428.0
Forward Power Contracts	Cash Flow Hedge	MWh		140.4		(4,705.7	)		(4,565.3	)
Forward Power Contracts	Mark to Market	MWh		3,177.8		(2,883.1	)		294.7

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 and our sale of retail power to third parties through our subsidiary DPLER. 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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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.

The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges:

	Year ended December 31, 2014						Year ended December 31, 2013					Year ended December 31, 2012
$ in millions (net of tax)	Power			Interest Rate Hedges			Power			Interest Rate Hedges		Power			Interest Rate Hedges
Beginning accumulated derivative gain / (loss) in AOCI	$	1.4		$	19.2		$	(3.0	)	$	0.5	$	0.3		$	(0.8	)
Net gains / (losses) associated with current period hedging transactions		(19.0	)		-			1.0			18.7		(2.6	)		1.1
Net gains reclassified to earnings:
Interest Expense		-			(0.9	)		-			-		-			0.2
Revenues		18.3			-			2.1			-		(0.7	)		-
Purchased Power		(0.5	)		-			1.3			-		-			-
Ending accumulated derivative gain / (loss) in AOCI	$	0.2		$	18.3		$	1.4		$	19.2	$	(3.0	)	$	0.5
Net gains / (losses) associated with the ineffective portion of the hedging transaction
Interest Expense	$	-		$	-		$	-		$	0.8	$	-		$	0.2
Portion expected to be reclassified to earnings in the next twelve months (a)	$	3.5		$	(0.9	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		24			0

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

Mark to Market Accounting

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

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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 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, 2014, 2013 and 2012:

Year ended December 31, 2014
$ in millions	Heating Oil			FTRs			Power			Natural Gas			Total
Derivatives not designated as hedging instruments
Change in unrealized loss	$	(0.6	)	$	(0.8	)	$	(1.5	)	$	(0.1	)		(3.0	)
Realized gain / (loss)		(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	)

Year ended December 31, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Derivatives not designated as hedging instruments
Change in unrealized gain	$	-	$	0.3	$	0.6	$	0.9
Realized gain		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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Year ended December 31, 2012
$ in millions	NYMEX Coal			Heating Oil			FTRs			Power			Total
Derivatives not designated as hedging instruments
Change in unrealized gain / (loss)	$	14.5		$	(1.6	)	$	(0.2	)	$	4.3		$	17.0
Realized gain / (loss)		(29.5	)		1.9			0.5			(5.0	)		(32.1	)
Total	$	(15.0	)	$	0.3		$	0.3		$	(0.7	)	$	(15.1	)
Recorded on Balance Sheet:
Partners' share of gain	$	4.2		$	-		$	-		$	-		$	4.2
Regulatory (asset) / liability		1.0			(0.6	)		-			-			0.4
Recorded in Income Statement:  gain / (loss)
Revenue		-			-			-			(5.1	)		(5.1	)
Purchased Power		-			-			0.3			4.4			4.7
Fuel		(20.2	)		0.7			-			-			(19.5	)
O&M		-			0.2			-			-			0.2
Total	$	(15.0	)	$	0.3		$	0.3		$	(0.7	)	$	(15.1	)

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The following tables show the fair value and balance sheet classification of DPL’s derivative instruments at December 31, 2014 and 2013.

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	Cash Flow		$	5.6	$	(2.0)	$	-	$	3.6
Forward power contracts	MTM			5.5		(3.4)		-		2.1
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow			0.3		(0.3)		-		-
Forward power contracts	MTM			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	Cash Flow		$	2.1	$	(2.0)	$	-	$	0.1
Forward power contracts	MTM			7.5		(3.4)		(4.1)		-
FTRs	MTM			0.6		-		-		0.6
Heating oil futures	MTM			0.4		-		(0.4)		-
Natural gas		MTM		0.1		-		(0.1)		-
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow			0.6		(0.3)		(0.3)		-
Forward power contracts	MTM			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.

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Fair Values of Derivative Instruments
December 31, 2013
				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	Cash Flow	$	0.5	$	(0.2)	$	-	$	0.3
Forward power contracts	MTM		4.9		(4.2)		-		0.7
FTRs	MTM		0.2		-		-		0.2
Heating oil futures	MTM		0.2		-		(0.2)		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		3.0		-		(3.0)		-
Forward power contracts	MTM		5.0		(0.3)		-		4.7
Total assets		$	13.8	$	(4.7)	$	(3.2)	$	5.9
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	2.7	$	(0.2)	$	(2.3)	$	0.2
Forward power contracts	MTM		6.6		(4.2)		(2.3)		0.1
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	MTM		1.3		(0.3)		(1.0)		-
Total liabilities		$	10.6	$	(4.7)	$	(5.6)	$	0.3

(a) Includes credit valuation adjustment.

As of December 31, 2013, this table includes Forward power contracts in a short-term asset position of $5.4 million and a long-term asset position of $8.0 million. This table does not include a short-term asset position of $0.9 million or a long-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.

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. Since our debt has fallen below investment grade, 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, 2014 is $12.2 million. This amount is offset by $4.9 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 $6.6 million. Since our debt is below investment grade, we could have to post collateral for the remaining $0.7 million.

Note 11 – Redeemable Preferred Stock

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

		December 31, 2014 and 2013				Carrying Value (a) ($ in millions)
	Preferred Stock Rate	Redemption price ($ per share)		Shares Outstanding		December 31, 2014		December 31, 2013
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, 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 as of December 31, 2014. 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.

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, as of December 31, 2014, DP&L’s retained earnings of $381.8 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.

Note 12 – Common Shareholders’ Equity

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, 2014.

As of December 31, 2014, there was no Event of Default - DPL’s Articles generally define an “Event of Default” as either (i) a breach of a covenant or obligation under the Articles; (ii) the entering of an order of insolvency or bankruptcy by a court and that order remains in effect and unstayed for 180 days; or (iii) DPL, DP&L or one of its principal subsidiaries commences a voluntary case under bankruptcy or insolvency laws or consents to the appointment of a trustee, receiver or custodian to manage all of the assets of DPL, DP&L or one of its principal subsidiaries – but DPL’s leverage ratio was at 0.93 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, 2014, DPL was prohibited under its Articles from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).

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Note 13 – 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 and its wholly-owned subsidiary, MC Squared, 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, 2014, DPL had $20.5 million of guarantees to third parties for future financial or performance assurance under such agreements, including $2.0 million of guarantees on behalf of DPLER, $18.3 million of guarantees on behalf of DPLE and $0.2 million of guarantees on behalf of MC Squared. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of DPLER, DPLE and MC Squared to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries.  The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Consolidated Balance Sheets was $1.6 million and $0.2 million at December 31, 2014 and 2013, respectively.

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

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. As of December 31, 2014, DP&L could be responsible for the repayment of 4.9%, or $74.4 million, of a $1,517.9 million debt obligation comprised of both fixed and variable rate securities with maturities between 2015 and 2040. This would only happen if this electric generation company defaulted on its debt payments. At December 31, 2014, 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, 2014, 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)		486.2		255.6		161.2		69.4		-
Limestone contracts (a)		18.3		6.1		12.2		-		-
Purchase orders and other contractual obligations		72.4		39.2		17.3		15.9		-

(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. As of December 31, 2014, 57% 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.

Limestone contracts:

DPL, through its principal subsidiary DP&L, has entered into various limestone contracts to supply limestone used in the operation of FGD equipment at its generating facilities.

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Purchase orders and other contractual obligations:

As of December 31, 2014, 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, 2014, 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 $0.8 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, which are disclosed in the paragraphs below. 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.

Environmental Matters Related to Air Quality

Clean Air Act Compliance

In 1990, the federal government amended the CAA to further regulate air pollution. Under the CAA, the USEPA sets limits on how much of a pollutant can be in the ambient air anywhere in the United States. The CAA allows individual states to have stronger pollution controls than those set under the CAA, but states are not allowed to have

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weaker pollution controls than those set for the whole country. The CAA has a material effect on our operations and such effects are detailed below with respect to certain programs under the CAA.

Clean Air Interstate Rule/Cross-State Air Pollution Rule

The USEPA promulgated CAIR on March 10, 2005, which required allowance surrender for SO₂ and NO_x emissions from existing power stations located in 27 eastern states and the District of Columbia. To implement the required emission reductions for this rule, the states were to establish emission-allowance-based “cap-and-trade” programs. CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the USEPA.

On July 7, 2011, the USEPA proposed CSAPR to replace CAIR. CSAPR required significant reductions in SO₂ and NOx emissions from covered sources, such as power stations in 28 eastern states including Ohio. On August 21, 2012, a three-judge panel of the D.C. Circuit Court vacated CSAPR, ruling that the USEPA overstepped its regulatory authority by requiring states to make reductions beyond the levels required in the CAA and failed to provide states an initial opportunity to adopt their own measures for achieving federal compliance. As a result of this ruling, the surviving provisions of CAIR continued to serve as the governing program. On June 24, 2013, the U.S. Supreme Court agreed to review the D.C. Circuit Court’s decision to vacate CSAPR, and on April 29, 2014, the U.S. Supreme Court reversed the 2012 decision by the D.C. Circuit Court, reinstating CSAPR, and remanded the case back to the D.C. Circuit Court for further proceedings consistent with the U. S. Supreme Court decision. On June 26, 2014, the U.S. Department of Justice, on behalf of the USEPA, filed a motion with the D.C. Circuit Court to lift the stay, and CSAPR was reinstated on October 23, 2014. The USEPA established new effective dates for compliance with the reduced emissions levels, beginning in 2015 with additional reductions in 2017. Oral arguments to address the remaining litigation regarding CSAPR are schedule for March 2015. At this time, it is not possible to predict with precision what impacts CSAPR may have on our consolidated financial condition, results of operations or cash flows, but we do not expect to have material capital costs to comply with CSAPR.

Mercury and Other Hazardous Air Pollutants

On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired electric generating units. The standards include new requirements for emissions of mercury and a number of other heavy metals. The USEPA Administrator signed the final rule, now called MATS, on December 16, 2011, and the rule was published in the Federal Register on February 16, 2012. Our affected EGUs must come into compliance with the new requirements by April 16, 2015. All of our operating EGUs are expected to be able to achieve compliance through control technologies that are currently in place.

On January 31, 2013, the USEPA finalized a rule regulating emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers and process heaters at major and area source facilities. This regulation affects seven auxiliary boilers used for start-up purposes at DP&L’s generation facilities. The regulation contains emissions limitations, operating limitations and other requirements. DP&L expects to be in compliance with this rule and the costs are not currently expected to be material to DP&L’s operations.

National Ambient Air Quality Standards

On January 5, 2005, the USEPA published its final non-attainment designations for the National Ambient Air Quality Standard (NAAQS) for Fine Particulate Matter 2.5 (PM 2.5). These designations included counties and partial counties in which DP&L operates and/or owns generating facilities. On December 31, 2012, the USEPA re-designated Adams County, where the Stuart and Killen generating stations are located, to attainment status. On December 14, 2012, the USEPA tightened the PM 2.5 standard to 12.0 micrograms per cubic meter, and on December 18, 2014, issued a pre-publication version of the final attainment designations. No counties containing DP&L operated generating facilities were designated as non-attainment, however, several co-owned units are located in non-attainment counties. Attainment in those counties will be required by the end of 2021. We cannot predict the effect the revisions to the PM 2.5 standard will have on DP&L’s financial condition or results of operations.

The USEPA published the national ground level ozone standard on March 12, 2008, lowering the 8-hour level from 0.08 ppm to 0.075 ppm, which was upheld by the U.S. Circuit Court of Appeals in July 2013. No DP&L operations are currently located in non-attainment areas. On December 17, 2014, the USEPA published a proposed rule lowering the 8-hour ozone standard from 0.075 to a value between 0.065 and 0.070 ppm. The USEPA intends to finalize the rule regarding the ozone NAAQS by October 2015, with initial designations to be issued in October 2017. In addition, in December 2013, eight northeastern states petitioned the USEPA to add nine upwind states,

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including Ohio, to the Ozone Transport Region, a group of states required to impose enhanced restrictions on ozone emissions. If the petition is granted, our facilities could be subject to such enhanced requirements. We cannot predict the effect the revisions of the ozone standard will have on DP&L’s financial condition or results of operations.

Effective April 12, 2010, the USEPA implemented revisions to its primary NAAQS for nitrogen dioxide. This change may affect certain emission sources in heavy traffic areas like the I-75 corridor between Cincinnati and Dayton after 2016. Several of our facilities or co-owned facilities are within this area. DP&L cannot determine the effect of this potential change, if any, on its operations.

Effective August 23, 2010, the USEPA implemented its revisions to its primary NAAQS for SO₂ replacing the previous 24-hour standard and annual standard with a one-hour standard. Initial non-attainment designations were made July 25, 2013, and Pierce Township in Clermont County, location of DP&L’s co-owned unit Beckjord Unit 6, was the only area with DP&L operations designated as non-attainment. Beckjord Unit 6 was retired effective October 1, 2014. Non-attainment areas will be required to meet the 2010 standard by October 2018. On April 17, 2014, the USEPA proposed a data requirements rule for air agencies to ascertain attainment characterization more extensively across the country by additional modeling and/or monitoring requirements of areas with sources that exceed specified thresholds of SO₂ emissions. The rule, if finalized, could require the installation of monitors at one or more of DP&L’s coal-fired power plants and result in additional non-attainment designations that could impact our operations. DP&L is unable to determine the effect of the proposed rule on its operations.

On May 5, 2004, the USEPA issued its proposed regional haze rule, which addresses how states should determine the Best Available Retrofit Technology (BART) for sources covered under the regional haze rule. Final rules were published July 6, 2005, providing states with several options for determining whether sources in the state should be subject to BART. Numerous units owned and operated by us will be affected by BART. We cannot determine the extent of the impact until Ohio determines how BART will be implemented.

Carbon Dioxide and Other Greenhouse Gas Emissions

The USEPA began regulating GHG emissions from certain stationary sources in January 2011 under regulations referred to as the “Tailoring Rule.” The regulations are implemented pursuant to two CAA programs: the Title V Operating Permit program and the program requiring a permit if undergoing certain new construction or major modifications, the Prevention of Significant Deterioration, or PSD, program. Obligations relating to Title V permits include recordkeeping and monitoring requirements. Sources subject to PSD can be required to implement Best Available Control Technology, or BACT. In June 2014, the U.S. Supreme Court ruled that the USEPA had exceeded its statutory authority in issuing the Tailoring Rule under Section 165 of the CAA by regulating sources under the PSD program based solely on their GHG emissions. However, the U.S. Supreme Court also held that the USEPA could impose GHG BACT requirements for sources already required to implement PSD for certain other pollutants. Therefore, if future modifications to DP&L’s sources require PSD review for other pollutants, it may also trigger GHG BACT requirements. The USEPA has issued guidance on what BACT entails for the control of GHG and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate impact of the BACT requirements applicable to us on our operations cannot be determined at this time as DP&L will not be required to implement BACT until DP&L constructs a new major source or makes a major modification of an existing major source. However, the cost of compliance could be material.

In January 2014, the USEPA proposed revised GHG New Source Performance Standards for new EGUs under CAA subsection 111(b), which would require new EGUs to limit the amount of CO₂ emitted per megawatt-hour. The proposal anticipates that affected coal-fired units would need to rely upon partial implementation of carbon capture and storage or other expensive CO₂ emission control technology to meet the standard. In addition, new natural gas-fired EGUs must meet a standard of no greater than 1,000 pounds of CO₂ per megawatt hour (if the rule is finalized in its current form). The rule is expected to be finalized this summer.

The USEPA issued proposed rules establishing GHG performance standards for existing power plants under CAA Section 111(d) on June 2, 2014. Under the proposed rule, called the Clean Power Plan, states would be judged against state-specific carbon dioxide emissions targets beginning in 2020, with expected total U.S. power section emissions reduction of 30% from 2005 levels by 2030. For Ohio specifically, the Clean Power Plan proposes an interim goal for 2020-2029 and a proposed 2030 final goal of 1,452 pounds of CO₂ per megawatt hour and 1,338 pounds of CO₂ per megawatt hour, respectively, a reduction of approximately 28% from 2012 levels. The proposed

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rule requires states to submit SIPs to meet the standards set forth in the rule by June 30, 2016, with the possibility of one- or two-year extensions under certain circumstances. The proposed rule requires states to submit SIPs to meet the standards set forth in the rule by June 30, 2016, with the possibility of one or two-year extensions under certain circumstances. The proposed rule requires states to submit SIPs to meet the standards set forth in the rule by June 30, 2016, with the possibility of one- or two-year extensions under certain circumstances. The proposed rule was subject to a public comment process and the USEPA is expected to finalize it by the summer of 2015. Among other things, we could be required to make efficiency improvements to existing facilities. The USEPA also issued proposed carbon pollution standards for modified and reconstructed power plants on June 2, 2014, which are also expected to be finalized by the summer of 2015. Various states and certain regulated entities have filed lawsuits challenging the Clean Power Plan. However, it is too soon to determine what the rule, and the corresponding SIPs affecting our operations, will require once they are finalized, whether they will survive judicial and other challenges, and if so, whether and when the rule and the corresponding SIP would materially impact our business, operations or financial condition.

Approximately 99% of the energy we produce is generated by coal. DP&L’s share of CO₂ emissions at generating stations we own and co-own is approximately 14 million tons annually. Further GHG legislation or regulation implemented at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial condition. However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial effect that such legislation or regulation may have on DP&L.

Litigation, Notices of Violation and Other Matters Related to Air Quality

Litigation Involving Co-Owned Stations

As a result of a 2008 consent decree entered into with the Sierra Club and approved by the U.S. District Court for the Southern District of Ohio, DP&L and the other owners of the Stuart generating station are subject to certain specified emission targets related to NO_x, SO₂ and particulate matter. The consent decree also includes commitments for energy efficiency and renewable energy activities. An amendment to the consent decree was entered into and approved in 2010 to clarify how emissions would be computed during malfunctions. Continued compliance with the consent decree, as amended, is not expected to have a material effect on DP&L’s results of operations, financial condition or cash flows in the future.

Notices of Violation Involving Co-Owned Units

In June 2000, the USEPA issued an NOV to the DP&L-operated Stuart generating station (co-owned by DP&L, Duke Energy and AEP Generation) for alleged violations of the CAA. The NOV contained allegations consistent with NOVs and complaints that the USEPA had brought against numerous other coal-fired utilities in the Midwest. The NOV indicated the USEPA may: (1) issue an order requiring compliance with the requirements of the Ohio SIP; or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. To date, neither action has been taken. DP&L cannot predict the outcome of this matter.

In December 2007, the Ohio EPA issued an NOV to the DP&L-operated Killen generating station (co-owned by DP&L and Duke Energy) for alleged violations of the CAA. The NOV alleged deficiencies in the continuous monitoring of opacity. We submitted a compliance plan to the Ohio EPA on December 19, 2007. To date, no further actions have been taken by the Ohio EPA.

On March 13, 2008, Duke Energy, the operator of the Zimmer generating station, received an NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio SIP and permits for the station in areas including SO₂, opacity and increased heat input. A second NOV and FOV with similar allegations was issued on November 4, 2010. Also in 2010, the USEPA issued an NOV to Zimmer for excess emissions. In addition, Zimmer received an NOV from the USEPA dated December 16, 2014 alleging violations in opacity on two dates in 2014. DP&L is a co-owner of the Zimmer generating station and could be affected by the eventual resolution of these matters. Duke Energy is expected to act on behalf of itself and the co-owners with respect to these matters. DP&L is unable to predict the outcome of these matters.

In January 2015, DP&L received NOVs from the USEPA alleging violations in opacity at the Stuart and Killen generating stations in 2014. DP&L is beginning the process of discussions with the USEPA on these NOVs. DP&L is unable to predict the outcome of these matters.

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Notices of Violation Involving Wholly-Owned Stations

On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. DP&L does not believe that the two projects described in the NOV were modifications subject to NSR. As a result of the cessation of operations of the six coal-fired units at the Hutchings Station, DP&L believes that the USEPA is unlikely to pursue the NSR complaint.

Environmental Matters Related to Water Quality, Waste Disposal and Ash Ponds

Clean Water Act – Regulation of Water Intake

On May 19, 2014, the USEPA finalized new regulations pursuant to the CWA governing existing facilities that have cooling water intake structures. The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal. Although we do not yet know the full impact the final rules will have on our operations, the final rules may require material changes to the intake structure at Stuart Station to reduce impingement with the possibility of additional site specific requirements for reducing entrainment. We do not believe the final rules will have a material impact on operations at any of the other DP&L-operated facilities.

Clean Water Act – Regulation of Water Discharge

In December 2006, DP&L submitted a renewal application for the Stuart generating station NPDES permit that was due to expire on June 30, 2007. The Ohio EPA issued a revised draft permit that was received on November 12, 2008. In September 2010, the USEPA formally objected to the November 12, 2008 revised permit due to questions regarding the basis for the alternate thermal limitation. At DP&L’s request, a public hearing was held on March 23, 2011, where DP&L presented its position on the issue and provided written comments. In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA. This reaffirmation stipulated that if the Ohio EPA did not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit would pass to the USEPA. The Ohio EPA issued another draft permit in December 2011 and a public hearing was held on February 2, 2012.

The draft permit required DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system. DP&L submitted comments to the draft permit. In November 2012, the Ohio EPA issued another draft which included a compliance schedule for performing a study to justify an alternate thermal limitation and to which DP&L submitted comments. In December 2012, the USEPA formally withdrew their objection to the permit. On January 7, 2013, the Ohio EPA issued a final permit. On February 1, 2013, DP&L appealed various aspects of the final permit to the Environmental Review Appeals Commission. A hearing before the Commission is scheduled for March 2015. Depending on the outcome of the appeal process, the effects on DP&L’s operations could be material.

In September 2009, the USEPA announced that it would be revising technology-based regulations governing water discharges from steam electric generating facilities. The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities. The proposed rule was released on June 7, 2013. Under a consent decree, the USEPA is required to issue a final rule by September 2015. At present, DP&L is unable to predict the impact this rulemaking will have on its operations.

A final NPDES permit for Killen Station was issued on September 4, 2014. We do not expect the new permit to have a material impact on Killen’s operations.

In January 2014, DP&L submitted an application for the renewal of the Hutchings Station NPDES permit which expired in July 2014. A final permit was issued on September 19, 2014 with an effective date of November 1, 2014. We do not expect the new permit to have a material impact on Hutchings’ operations.

Regulation of Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site. In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach. In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS. No recent activity has occurred with respect to that notice or PRP status. On August 16, 2006, an Administrative Settlement Agreement and Order on Consent

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(“ASAOC”) was executed and became effective among a group of PRPs, not including DP&L, and the USEPA. On August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site. DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010. On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site. On February 10, 2011, the Court dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The Court, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck to the landfill. Discovery, including depositions of past and present DP&L employees, was conducted in 2012. On February 8, 2013, the Court granted DP&L’s motion for summary judgment on statute of limitations grounds with respect to claims seeking a contribution toward the costs that are expected to be incurred by the PRP group in performing an RI/FS under the August 15, 2006 ASAOC. That summary judgment ruling was appealed on March 4, 2013, and on July 14, 2014, a three-judge panel of the U.S. Court of Appeals for the 6^th Circuit affirmed the lower Court’s ruling and subsequently denied a request by the plaintiffs for rehearing. On November 14, 2014, the PRP group appealed the decision to the U.S. Supreme Court, but the writ of certiorari was denied by the Court on January 20, 2015. On January 14, 2015, the PRP group served DP&L and other defendants a request for production of documents related to any survey regarding waste management or waste disposal. Information responsive to this request was provided on February 17, 2015. In addition, on January 16, 2015, the USEPA issued a Special Notice Letter and Section 104(e) Information Request to DP&L and other defendants, requesting historical information related to waste management practices. DP&L is in the process of developing its response to the request which is due by March 20, 2015. DP&L is unable to predict the outcome of this action by the plaintiffs and USEPA. Additionally, the Court’s 2013 ruling and the Court of Appeals’ affirmation of that ruling in 2014 does not address future litigation that may arise with respect to actual remediation costs. While DP&L is unable to predict the outcome of these matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.

In December 2003, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the Tremont City landfill site. Information available to DP&L does not demonstrate that it contributed hazardous substances to the site. While DP&L is unable to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.

On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCBs). While this reassessment is in the early stages and the USEPA is seeking information from potentially affected parties on how it should proceed, the outcome may have a material effect on DP&L. A proposed rule is expected in mid-2015, with a final rule expected in 2016. At present, DP&L is unable to predict the impact this initiative will have on its operations.

Regulation of Ash Ponds

In March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and Stuart Stations. Subsequently, the USEPA collected similar information for the Hutchings Station.

In August 2010, the USEPA conducted an inspection of the Hutchings Station ash ponds. In June 2011, the USEPA issued a final report from the inspection including recommendations relative to the Hutchings Station ash ponds. DP&L is unable to predict whether there will be additional USEPA action relative to DP&L’s proposed plan or the effect on operations that might arise under a different plan.

In June 2011, the USEPA conducted an inspection of the Killen Station ash ponds. In May 2012, we received a draft report on the inspection. DP&L submitted comments on the draft report in June 2012. On March 14, 2013, DP&L received the final report on the inspection of the Killen Station ash pond inspection from the USEPA which

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included recommended actions. DP&L has submitted a response with its actions to the USEPA. DP&L is unable to predict the outcome this inspection will have on its operations.

There has been increasing advocacy to regulate coal combustion residuals (CCR) under the Resource Conservation Recovery Act (RCRA). On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion byproducts including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. The USEPA released its final rule on December 19, 2014, designating coal combustion residuals that are not beneficially reused as non-hazardous solid waste under RCRA Subtitle D. The rule becomes effective six months after publication of the rule in the Federal Register, expected in February 2015, and applies new detailed management practices to new and existing landfills and surface impoundments, including lateral expansions of such units. DP&L is currently reviewing the rule and assessing the impact on our operations. Our business, financial condition or operations could be materially and adversely affected by this regulation.

Notice of Violation Involving Co-Owned Units

On September 9, 2011, DP&L received an NOV from the USEPA with respect to its co-owned Stuart generating station based on a compliance evaluation inspection conducted by the USEPA and Ohio EPA in 2009. The notice alleged non-compliance by DP&L with certain provisions of the RCRA, the CWA NPDES permit program and the station’s storm water pollution prevention plan. The notice requested that DP&L respond with the actions it has subsequently taken or plans to take to remedy the USEPA’s findings and ensure that further violations will not occur. Based on its review of the findings, although there can be no assurance, we believe that the notice will not result in any material effect on DP&L’s results of operations, financial condition or cash flows.

Legal and Other Matters

In February 2007, DP&L filed a lawsuit in the United States District Court for Southern District of Ohio against Appalachian Fuels, LLC (“Appalachian”) seeking damages incurred due to Appalachian’s failure to supply approximately 1.5 million tons of coal to two commonly-owned stations under a coal supply agreement, of which approximately 570 thousand tons was DP&L’s share. DP&L obtained replacement coal to meet its needs. Appalachian has denied liability, and is currently in federal bankruptcy proceedings in which DP&L is participating as an unsecured creditor. DP&L is unable to determine the ultimate resolution of this matter. DP&L has not recorded any assets relating to possible recovery of costs in this lawsuit.

In connection with DP&L and other utilities joining PJM, in 2006, the FERC ordered utilities to eliminate certain charges to implement transitional payments, known as SECA, effective December 1, 2004 through March 31, 2006, subject to refund. Through this proceeding, DP&L was obligated to pay SECA charges to other utilities, but received a net benefit from these transitional payments. A hearing was held and an initial decision was issued in August 2006. A final FERC order on this issue was issued on May 21, 2010 that substantially supports DP&L’s and other utilities’ position that SECA obligations should be paid by parties that used the transmission system during the timeframe stated above. Prior to this final order being issued, DP&L entered into a significant number of bilateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the final decision. On July 5, 2012, a Stipulation was executed and filed with the FERC that resolved SECA claims against BP Energy Company (“BP”) and DP&L, AEP (and its subsidiaries) and Exelon Corporation (and its subsidiaries). On October 1, 2012, DP&L received the $14.6 million (including interest income of $1.8 million) from BP and recorded the settlement in the third quarter; at December 31, 2012, there is no remaining balance in other deferred credits related to SECA.

Note 14 – Business Segments

DPL operates through two segments consisting of the operations of two of its wholly-owned subsidiaries, DP&L (Utility segment) and DPLER (Competitive Retail segment which includes DPLER’s wholly-owned subsidiary, MC Squared). This is how we view our business and make decisions on how to allocate resources and evaluate performance.

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 more than 516,000 retail

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customers who are located in a 6,000 square mile area of West Central Ohio. DP&L also sells 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.

The Competitive Retail segment is DPLER’s competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or its subsidiary MC Squared as their alternative electric supplier. The Competitive Retail segment sells electricity to approximately 260,000 customers currently located throughout Ohio and in Illinois. 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 are based on fixed-price contracts for each customer; the price approximates market prices for wholesale power at the inception of each customer’s contract. DP&L started selling power to MC Squared during June 2012 and became their sole source of power in September 2012 under the same terms as above. The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.

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.

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

$ 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 5)	$	-	$	-	$	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	$	(23.7	)	$	-		$	18.0
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 5)	$	-	$	-	$	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.

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$ in millions	Utility		Competitive Retail		Other			Adjustments and Eliminations			DPL Consolidated
Year ended December 31, 2012
Revenues from external customers	$	1,138.4	$	493.1	$	36.9		$	-		$	1,668.4
Intersegment revenues		393.4		-		3.4			(396.8	)		-
Total revenues		1,531.8		493.1		40.3			(396.8	)		1,668.4
Fuel		354.9		-		7.0			-			361.9
Purchased power		309.5		424.5		1.5			(393.4	)		342.1
Amortization of intangibles		-		-		95.1			-			95.1
Gross margin (a)	$	867.4	$	68.6	$	(63.3	)	$	(3.4	)	$	869.3
Depreciation and amortization	$	141.3	$	0.4	$	(16.3	)	$	-		$	125.4
Goodwill impairment (Note 5)	$	-	$	-	$	1,817.2		$	-		$	1,817.2
Fixed asset impairment	$	80.8	$	-	$	(80.8	)	$	-		$	-
Interest expense	$	39.1	$	0.6	$	83.9		$	(0.7	)	$	122.9
Income tax expense / (benefit)	$	55.1	$	18.1	$	(25.5	)	$	-		$	47.7
Net income / (loss)	$	91.2	$	22.8	$	(1,725.4	)	$	(118.4	)	$	(1,729.8	)
Cash capital expenditures	$	195.5	$	-	$	2.6		$	-		$	198.1
Total assets (end of year)	$	3,464.2	$	99.2	$	683.9		$	-		$	4,247.3

(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

During the first quarter of 2014, DP&L 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. DP&L 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 Business Segments (Note 14) 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.

During the fourth quarter of 2013, the Company 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. The Company 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 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

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approach. As a result, the Company recognized an asset impairment expense of $26.2 million. Conesville is reported in the Utility segment.

Schedule II

DPL Inc.
VALUATION AND QUALIFYING ACCOUNTS
For each of the three years ended December 31, 2012 - 2014
$ in thousands
Description	Balance at Beginning of Period		Additions		Deductions (a)		Balance at End of Period
Year ended December 31, 2014
Deducted from accounts receivable -
Provision for uncollectible accounts	$	1,160	$	7,644	$	7,537	$	1,267
Deducted from deferred tax assets -
Valuation allowance for deferred tax assets	$	13,721	$	5,179	$	-	$	18,900
Year ended December 31, 2013
Deducted from accounts receivable -
Provision for uncollectible accounts	$	1,084	$	6,156	$	6,080	$	1,160
Deducted from deferred tax assets -
Valuation allowance for deferred tax assets	$	12,349	$	2,159	$	787	$	13,721
Year ended December 31, 2012
Deducted from accounts receivable -
Provision for uncollectible accounts	$	1,136	$	5,902	$	5,954	$	1,084
Deducted from deferred tax assets -
Valuation allowance for deferred tax assets	$	6,702	$	6,747	$	1,100	$	12,349
(a) Amounts written off, net of recoveries of accounts previously written off.

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DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
	Three months ended March 31,
$ in millions	2015			2014
Revenues	$	494.5		$	460.3
Cost of revenues:
Fuel		76.4			90.0
Purchased power		194.2			174.1
Amortization of intangibles		-			0.3
Total cost of revenues		270.6			264.4
Gross margin		223.9			195.9
Operating expenses:
Operation and maintenance		91.7			104.7
Depreciation and amortization		35.0			35.3
General taxes		24.1			27.6
Goodwill impairment		-			135.8
Fixed-asset impairment		-			11.5
Other		0.5			0.3
Total operating expenses		151.3			315.2
Operating income / (loss)		72.6			(119.3	)
Other income / (expense), net:
Investment income / (loss)		(0.2	)		0.4
Interest expense		(30.5	)		(30.8	)
Other expense		(0.5	)		(0.5	)
Total other expense		(31.2	)		(30.9	)
Earnings / (loss) before income taxes		41.4			(150.2	)
Income tax expense		12.7			98.8
Net income / (loss)	$	28.7		$	(249.0	)

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

F-63

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
	Three months ended March 31,
$ in millions	2015			2014
Net income / (loss)	$	28.7		$	(249.0	)
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax (expense) / benefit of $(0.3) and $0.2 for each respective period		0.5			(0.3	)
Reclassification to earnings, net of income tax (expense) / benefit of $0.2 and $(0.1) for each respective period		(0.4	)		0.2
Total change in fair value of available-for-sale securities		0.1			(0.1	)
Derivative activity:
Change in derivative fair value, net of income tax (expense) / benefit of $(0.1) and $7.0 for each respective period		0.1			(12.9	)
Reclassification to earnings, net of income tax expense of $(0.3) and $(3.1) for each respective period		0.6			5.5
Total change in fair value of derivatives		0.7			(7.4	)
Pension and postretirement activity:
Reclassification to earnings, net of income tax expense of $0.0 and $0.0 for each respective period		0.1			-
Total change in unfunded pension obligation		0.1			-
Other comprehensive income / (loss)		0.9			(7.5	)
Net comprehensive income / (loss)	$	29.6		$	(256.5	)
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

F-64

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	Three months ended March 31,
$ in millions	2015			2014
Cash flows from operating activities:
Net income / (loss)	$	28.7		$	(249.0	)
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Depreciation and amortization		35.0			35.3
Amortization of intangibles		-			0.3
Deferred income taxes		(1.0	)		(3.2	)
Goodwill Impairment		-			135.8
Fixed-asset impairment		-			11.5
Changes in certain assets and liabilities:
Accounts receivable		3.8			(13.7	)
Inventories		5.2			(8.0	)
Prepaid taxes		0.6			1.4
Taxes applicable to subsequent years		19.1			14.0
Deferred regulatory costs, net		11.4			(7.7	)
Accounts payable		(20.4	)		36.9
Accrued taxes payable		(24.7	)		75.6
Accrued interest payable		6.8			14.5
Pension, retiree and other benefits		2.0			0.8
Other		(0.6	)		(31.6	)
Net cash from operating activities		65.9			12.9
Cash flows from investing activities:
Capital expenditures		(33.7	)		(28.4	)
Purchase of emission allowances		-			(0.1	)
Purchase of renewable energy credits		(0.2	)		(1.2	)
Decrease / (increase) in restricted cash		(0.8	)		(15.6	)
Other investing activities, net		0.3			-
Net cash from investing activities		(34.4	)		(45.3	)
Net cash from financing activities:
Borrowings from revolving credit facilities		15.0			65.0
Repayment of borrowings from revolving credit facilities		(15.0	)		(65.0	)
Net cash from financing activities		-			-
Cash and cash equivalents:
Net change		31.5			(32.4	)
Balance at beginning of period		17.0			53.2
Cash and cash equivalents at end of period	$	48.5		$	20.8
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	20.8		$	15.0
Income taxes paid / (refunded), net	$	-		$	(0.3	)
Non-cash financing and investing activities:
Accruals for capital expenditures	$	11.2		$	9.4

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

F-65

DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
	March 31,			December 31,
$ in millions	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	48.5		$	17.0
Restricted cash		17.5			16.8
Accounts receivable, net (Note 2)		180.6			200.9
Inventories (Note 2)		94.9			100.2
Taxes applicable to subsequent years		58.7			77.8
Regulatory assets, current		34.9			44.2
Other prepayments and current assets		56.7			41.8
Total current assets		491.8			498.7
Property, plant & equipment:
Property, plant & equipment		2,792.1			2,759.3
Less: Accumulated depreciation and amortization		(347.1	)		(318.4	)
		2,445.0			2,440.9
Construction work in process		65.6			76.7
Total net property, plant & equipment		2,510.6			2,517.6
Other non-current assets:
Regulatory assets, non-current		156.8			167.5
Goodwill		317.0			317.0
Intangible assets, net of amortization		31.7			37.4
Other deferred assets		46.0			39.6
Total other non-current assets		551.5			561.5
Total assets	$	3,553.9		$	3,577.8
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

F-66

DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
	March 31,			December 31,
$ in millions	2015			2014
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt (Note 4)	$	30.1		$	20.1
Accounts payable		82.2			109.2
Accrued taxes		116.6			102.6
Accrued interest		34.1			27.2
Customer security deposits		13.7			14.4
Regulatory liabilities, current		6.8			4.4
Insurance and claims costs		5.6			6.4
Other current liabilities		46.1			48.7
Total current liabilities		335.2			333.0
Non-current liabilities:
Long-term debt (Note 4)		2,129.6			2,139.6
Deferred taxes		577.8			587.3
Taxes payable		42.2			80.9
Regulatory liabilities, non-current		124.6			124.1
Pension, retiree and other benefits		95.9			95.9
Unamortized investment tax credit		2.1			2.2
Other deferred credits		50.2			48.2
Total non-current liabilities		3,022.4			3,078.2
Redeemable preferred stock of subsidiary		18.4			18.4
Commitments and contingencies (Note 9)
Common shareholder's equity:
Common stock:
1,500 shares authorized; 1 share issued and outstanding at March 31, 2015 and December 31, 2014		-			-
Other paid-in capital		2,237.5			2,237.4
Accumulated other comprehensive income		8.4			7.5
Accumulated deficit		(2,068.0	)		(2,096.7	)
Total common shareholder's equity		177.9			148.2
Total liabilities and shareholder's equity	$	3,553.9		$	3,577.8
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

F-67

DPL Inc.

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Overview and Summary of Significant Accounting Policies

Description of Business

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’s two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER operations, which include the operations of DPLER’s wholly owned subsidiary MC Squared. MC Squared was sold effective April 1, 2015. See Note 10 for more information relating to these reportable segments. The terms “we,” “us,” “our” and “ours” are used to refer to DPL and its subsidiaries.

DPL is an indirectly wholly owned subsidiary of AES.

DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail services are still regulated. DP&L has the exclusive right to provide such distribution and transmission services to its more than 516,000 customers located in West Central Ohio. Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at five coal-fired power stations. During 2015, DP&L is required to source 60% of the generation for its SSO customers through a competitive bid process and beginning January 2016, generation for its SSO customers will be 100% 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, retail competition in our service territory and the market price of electricity. DP&L sells any excess energy and capacity into the wholesale market. DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER’s retail customers.

DPLER sells competitive retail electric service, under contract, to residential, commercial, industrial and governmental customers. As of March 31, 2015, DPLER’s operations include those of its wholly owned subsidiary MC Squared. DPLER has approximately 259,000 customers currently located throughout Ohio and Illinois. This number includes approximately 116,000 customers in Northern Illinois of MC Squared, a Chicago-based retail electricity supplier. On April 1, 2015, DPLER closed on the sale of MC Squared. After considering the sale of MC Squared on April 1, 2015, the Competitive Retail segment sold electricity to 143,000 customers. DPLER does not own any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&L to meet its sales obligations. DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the areas it serves.

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 our subsidiaries and us. DPL owns all of the common stock of its subsidiaries.

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

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

DPL and its subsidiaries employed 1,185 people as of March 31, 2015, of which 1,166 were employed by DP&L. Approximately 60% of all DPL employees are under a collective bargaining agreement that expires on October 31, 2017.

F-68

Financial Statement Presentation

DPL’s Condensed Consolidated Financial Statements include the accounts of DPL and its wholly owned subsidiaries except for DPL Capital Trust II, which is not consolidated, consistent with the provisions of GAAP. DP&L has undivided ownership interests in five coal-fired generating facilities, various peaking generating facilities and numerous transmission facilities, all of which are included in the financial statements at amortized cost, which was adjusted to fair value at the date of the Merger for DPL. Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Consolidated Statements of Operations. See Note 3 for more information.

All material intercompany accounts and transactions are eliminated in consolidation.

These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2014.

In the opinion of our management, the Condensed Consolidated Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31, 2015; our results of operations for the three months ended March 31, 2015 and 2014 and our cash flows for the three months ended March 31, 2015 and 2014. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including, but not limited to, seasonal weather variations, the timing of outages of EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three months ended March 31, 2015 may not be indicative of our results that will be realized for the full year ending December 31, 2015.

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

As a result of push down accounting, DPL’s Condensed Consolidated Statements of Operations subsequent to the Merger include amortization expense relating to purchase accounting adjustments and depreciation of fixed assets based upon their fair value.

As a result of the sale of MC Squared mentioned above, $0.4 million of cash and $17.4 million of accounts receivable have been reclassified to current assets held for sale, included in “Other prepayments and current assets” in the Condensed Consolidated Balance Sheet at March 31, 2015. Additionally, $0.6 million of property, plant and equipment (net of accumulated depreciation) and $1.4 million of intangible assets (net of amortization) have been reclassified to non-current assets held for sale, included in “Other deferred assets” in the Condensed Consolidated Balance Sheet at March 31, 2015.

Sale of Receivables

DPLER and its former subsidiary MC Squared sell their customer receivables. These sales are at a small discount for cash at the billed amounts for their customers’ use of energy. Total receivables sold during the three months ended March 31, 2015 and 2014 were $33.1 million and $32.2 million, respectively.

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

DPL collects certain excise taxes levied by state or local governments from its customers. These taxes are accounted for on a net basis and not included in revenue. The amounts of such taxes collected for the three months ended March 31, 2015 and 2014 were $14.0 million and $14.4 million, respectively.

F-69

Related Party Transactions

In December 2013, an agreement was signed, effective January 1, 2014, whereby the Service Company is to provide 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. 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 non-regulated businesses.

In the normal course of business, DPL enters into transactions with subsidiaries of AES. The following table provides a summary of these transactions:

	Three months ended
	March 31,
$ in millions	2015		2014
Transactions with the Service Company
Charges for services provided	$	9.8	$	10.4

Transactions with the Service Company	At March 31, 2015		At December 31, 2014
Net advances / (payable) to the Service Company	$	3.0	$	(4.7	)

DPL has issued debt to a wholly owned business trust, DPL Capital Trust II.

Recently Issued Accounting Standards

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 March 31, 2015, DPL had approximately $20.5 million in deferred financing costs classified in other noncurrent assets that would be reclassified to reduce the related debt liabilities upon adoption of ASU No. 2015-03.

F-70

2. Supplemental Financial Information

Accounts receivable and Inventories are as follows at March 31, 2015 and December 31, 2014:

	March 31,			December 31,
$ in millions	2015			2014
Accounts receivable, net:
Unbilled revenue	$	58.6		$	79.2
Customer receivables		109.3			104.8
Amounts due from partners in jointly owned plants		8.3			14.2
Other		5.8			4.0
Provision for uncollectible accounts		(1.4	)		(1.3	)
Total accounts receivable, net	$	180.6		$	200.9
Inventories, at average cost:
Fuel and limestone	$	58.9		$	65.3
Plant materials and supplies		34.3			33.5
Other		1.7			1.4
Total inventories, at average cost	$	94.9		$	100.2

Accumulated Other Comprehensive Income / (Loss)

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

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statements of Operations	Three months ended
		March 31,
$ in millions		2015		2014
Gains and losses on Available-for-sale securities activity (Note 7):
	Other income	$	(0.6)	$	0.3
	Tax expense		0.2		(0.1)
	Net of income taxes		(0.4)		0.2
Gains and losses on cash flow hedges (Note 8):
	Interest expense		(0.2)		(0.5)
	Revenue		(0.3)		10.2
	Purchased power		1.4		(1.1)
	Total before income taxes		0.9		8.6
	Tax expense		(0.3)		(3.1)
	Net of income taxes		0.6		5.5
Amortization of defined benefit pension items (Note 6):
	Other income		0.1		-
	Tax expense		-		-
	Net of income taxes		0.1		-
Total reclassifications for the period, net of income taxes		$	0.3	$	5.7

F-71

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the three months ended March 31, 2015 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities			Gains / (losses) on cash flow hedges		Change in unfunded pension obligation			Total
Balance January 1, 2015	$	0.5		$	18.5	$	(11.5	)	$	7.5
Other comprehensive income before reclassifications		0.5			0.1		-			0.6
Amounts reclassified from accumulated other comprehensive income / (loss)		(0.4	)		0.6		0.1			0.3
Net current period other comprehensive income		0.1			0.7		0.1			0.9
Balance March 31, 2015	$	0.6		$	19.2	$	(11.4	)	$	8.4

3. Ownership of Coal-fired Facilities

DP&L has undivided ownership interests in five coal-fired electric generating facilities, various peaking facilities and numerous transmission facilities with certain other Ohio utilities. 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 March 31, 2015, DP&L had $24.0 million of construction work in process at such jointly owned facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Consolidated Statements of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Consolidated Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly owned units and stations.

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

	DP&L Share			DPL Carrying value
Jointly owned production units and stations:	Ownership (%)	Summer Production Capacity (MW)		Gross Plant in Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)		SCR and FGD Equipment Installed and in Service (Yes/No)
Conesville Unit 4	16.5		129	$	25	$	2	$	1	Yes
Killen Station	67.0		402		308		22		4	Yes
Miami Fort Units 7 and 8	36.0		368		214		26		3	Yes
Stuart Station	35.0		808		220		17		12	Yes
Zimmer Station	28.1		371		185		37		4	Yes
Transmission (at varying percentages)			n/a		42		6		-
Total			2,078	$	994	$	110	$	24

F-72

DPL revalued DP&L’s investment in the above plants at the estimated fair value for each plant at the date of the Merger.

4. Debt Obligations

Long-term debt

	March 31,			December 31,
$ in millions	2015			2014
First mortgage bonds due in September 2016 - 1.875%	$	445.0		$	445.0
Pollution control series due in January 2028 - 4.7%		35.3			35.3
Pollution control series due in January 2034 - 4.8%		179.1			179.1
Pollution control series due in September 2036 - 4.8%		100.0			100.0
Pollution control series due in November 2040 - rates from: 0.02% - 0.05% and 0.04% - 0.15% (a)		100.0			100.0
U.S. Government note due in February 2061 - 4.2%		18.1			18.1
Unamortized debt discount		(2.8	)		(2.8	)
Total long-term debt at subsidiary		874.7			874.7
Bank term loan due in May 2018 - rates from: 2.41% - 2.43% and 2.42% - 2.45% (a)		130.0			140.0
Senior unsecured bonds due in October 2016 - 6.5%		130.0			130.0
Senior unsecured bonds due in October 2019 - 6.75%		200.0			200.0
Senior unsecured bonds due in October 2021 - 7.25%		780.0			780.0
Note to DPL Capital Trust II due in September 2031 - 8.125% (b)		15.6			15.6
Unamortized debt discount		(0.7	)		(0.7	)
Total non-current portion of long-term debt	$	2,129.6		$	2,139.6

Current portion of long-term debt

	March 31,		December 31,
$ in millions	2015		2014
Bank term loan due in May 2018 - rates from: 2.41% - 2.43% and 2.42% - 2.45% (a)	$	30.0	$	20.0
U.S. Government note due in February 2061 - 4.2%		0.1		0.1
Total current portion of long-term debt	$	30.1	$	20.1

(a) Range of interest rates for the three months ended March 31, 2015 and the twelve months ended December 31, 2014, respectively.

(b) Note payable to related party. See Note 1: Related Party Transactions for additional information.

F-73

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

Due within the twelve months ending March 31,
($ in millions)
2016	$	30.1
2017		615.1
2018		40.1
2019		50.2
2020		200.2
Thereafter		1,227.5
Total maturities		2,163.2
Unamortized premiums and discounts		(3.5	)
Total long-term debt	$	2,159.7

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

DP&L has a $300.0 million unsecured revolving credit agreement with a syndicated bank group. This $300.0 million facility has a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million. At March 31, 2015, there were two letters of credit in the amount of $1.4 million outstanding, with the remaining $298.6 million available to DP&L. Fees associated with this letter of credit facility were not material during the three months ended March 31, 2015 or 2014.

DP&L’s unsecured revolving credit agreement and DP&L’s amended standby letters of credit have two financial covenants, the first measures Total Debt to Total Capitalization. The Total Debt to Total Capitalization ratio is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant ratio compares EBITDA to Interest Expense ratio. 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 has a $100.0 million unsecured revolving credit facility. This $100.0 million facility has a $100.0 million letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility by an additional $50.0 million. This facility has a five year term expiring on May 10, 2018; however, if DPL has not refinanced its senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this facility shall be July 15, 2016. At March 31, 2015, there was one letter of credit in the amount of $2.3 million outstanding, with the remaining $97.7 million available to DPL. Fees associated with this facility were not material during the three months ended March 31, 2015 or 2014.

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

DPL’s unsecured revolving credit agreement and unsecured term loan restrict dividend payments from DPL to AES and adjust the cost of borrowing under the facilities under certain credit rating scenarios.

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

F-74

5. Income Taxes

The following table details the effective tax rates for the three months ended March 31, 2015 and 2014.

	Three months ended March 31,
	2015			2014
DPL		30.7	%		(65.8	)%

Income tax expense for the three months ended March 31, 2015 and 2014 was calculated using the estimated annual effective income tax rates for 2015 and 2014 of 31.1% and (65.8)%, respectively. For the three months ended March 31, 2015 and March 31, 2014, management estimated the annual effective tax rate based on its forecast of annual pre-tax income. To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates.

For the three months ended March 31, 2015, DPL’s current period effective rate was less than the estimated annual effective rate due to a discrete adjustment that was recorded to properly reflect the filed 2013 state income tax returns. The increase in the effective rate compared to the same period in 2014 is primarily due to not having a non-deductible goodwill impairment in 2015.

6. Pension and Postretirement Benefits

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

We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of ERISA and, in addition, make voluntary contributions from time to time. There were no contributions made during the three months ended March 31, 2015 or 2014.

The amounts presented in the following tables for pension include the collective bargaining plan formula, the traditional management plan formula, the cash balance plan formula and the SERP, in the aggregate.  The amounts presented for postretirement include both health and life insurance.  The pension and postretirement costs below have not been adjusted for amounts billed to the Service Company for former DP&L employees who are now employed by the Service Company but are still participants in the DP&L plan.  See "Related Party Transactions" discussion in Note 1, "Overview and Summary of Significant Accounting Policies".

The net periodic benefit cost / (income) of the pension and postretirement benefit plans for the three months ended March 31, 2015 and 2014 was:

Net Periodic Benefit Cost / (Income)	Pension						Postretirement
	Three months ended						Three months ended
	March 31,						March 31,
$ in millions	2015			2014			2015			2014
Service cost	$	1.8		$	1.5		$	-		$	0.1
Interest cost		4.3			4.4			0.2			0.2
Expected return on plan assets		(5.7	)		(5.8	)		-			(0.1	)
Amortization of unrecognized:
Prior service cost		0.5			0.4			-			-
Actuarial loss / (gain)		1.5			0.9			(0.1	)		(0.1	)
Net periodic benefit cost	$	2.4		$	1.4		$	0.1		$	0.1

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

$ in millions	Pension		Postretirement
2015	$	18.6	$	1.4
2016		25.2		1.8
2017		25.7		1.7
2018		26.3		1.6
2019		26.7		1.5
2020 - 2024		137.0		6.1

7. Fair Value Measurements

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

The following table presents the fair value and cost of our non-derivative instruments at March 31, 2015 and December 31, 2014. Information about the fair value of our derivative instruments can be found in Note 8.

	March 31, 2015				December 31, 2014
$ in millions	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets
Money market funds	$	0.1	$	0.1	$	0.1	$	0.1
Equity securities		2.7		3.8		2.7		3.7
Debt securities		4.6		4.6		4.7		4.7
Hedge funds		0.7		0.7		0.8		0.8
Real estate		0.3		0.4		0.4		0.4
Total Assets	$	8.4	$	9.6	$	8.7	$	9.7
Liabilities
Debt	$	2,159.7	$	2,238.5	$	2,159.7	$	2,204.8

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

Debt

Unrealized gains or losses are not recognized in the financial statements as debt is presented at 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 Master Trusts to hold assets that could be used for the benefit of employees participating in employee benefit plans and these assets are not used for general operating purposes. These assets are primarily comprised of open-ended mutual funds, which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.

DPL had $1.0 million ($0.7 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at March 31, 2015 and $0.8 million ($0.5 million after tax) of unrealized gains and immaterial unrealized losses in AOCI at December 31, 2014.

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During the three months ended March 31, 2015, $0.6 million ($0.4 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings. An immaterial amount of unrealized gains are expected to be reversed to earnings over the next twelve months to facilitate the distribution of benefits.

Fair Value Hierarchy

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

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

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

· 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 three months ended March 30, 2015 and 2014.

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The fair value of assets and liabilities at March 31, 2015 and 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 March 31, 2015		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		3.8		-		3.8		-
Debt securities		4.6		-		4.6		-
Hedge funds		0.7		-		0.7		-
Real estate		0.4		-		0.4		-
Total Master Trust assets		9.6		0.1		9.5		-
Derivative Assets
FTRs		0.3		-		-		0.3
Forward power contracts		20.3		-		18.8		1.5
Total Derivative assets		20.6		-		18.8		1.8
Total Assets	$	30.2	$	0.1	$	28.3	$	1.8
Liabilities
Derivative Liabilities
Heating oil		0.3		0.3		-		-
Forward power contracts		20.4		-		19.0		1.4
Total Derivative liabilities		20.7		0.3		19.0		1.4
Long-term debt		2,238.5		-		2,220.3		18.2
Total Liabilities	$	2,259.2	$	0.3	$	2,239.3	$	19.6

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Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2014		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		0.1		9.6		-
Derivative assets
Forward power contracts		14.9		-		13.7		1.2
Total Derivative assets		14.9		-		13.7		1.2
Total Assets	$	24.6	$	0.1	$	23.3	$	1.2
Liabilities
Derivative 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

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 observable prices based on 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. Other Level 3 inputs include the credit valuation adjustment on some of the forward power contracts and forward power contracts in less active markets. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.

Approximately 98% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Our debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. As the Wright-Patterson Air Force Base loan is not publicly traded, fair value is assumed to equal carrying value. These fair value

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

Non-recurring Fair Value Measurements

We use the cost approach to determine the fair value of our AROs, which is estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. AROs for ash ponds, asbestos and underground storage tanks increased by $0.6 million and $1.2 million during the three months ended March 31, 2015 and 2014, respectively.

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 Goodwill and Long-lived assets measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy (there were no impairments during the quarter ended March 31, 2015):

$ in millions	Three months ended March 31, 2014
	Carrying		Fair Value						Gross
	Amount (c)		Level 1		Level 2		Level 3		Loss
Assets
Long-lived assets (a)
DP&L (East Bend)	$	14.2	$	-	$	-	$	2.7	$	11.5
Goodwill (b)
DPLER Reporting unit	$	135.8	$	-	$	-	$	-	$	135.8

(a) See Note 12 for further information

(b) See Note 11 for further information

(c) Carrying amount at date of valuation

8. 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. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as normal purchase/normal sale, cash flow hedges or marked to market each reporting period.

At March 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	Mark to Market	MWh		4.2		-			4.2
Heating oil futures	Mark to Market	Gallons		252.0		-			252.0
Forward power contracts	Cash Flow Hedge	MWh		843.5		(3,708.3	)		(2,864.8	)
Forward power contracts	Mark to Market	MWh		1,565.1		(4,826.9	)		(3,261.8	)

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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	Mark to Market	MWh		10.5		-			10.5
Heating oil futures	Mark to Market	Gallons		378.0		-			378.0
Natural gas futures	Mark to Market	Dths		200.0		-			200.0
Forward power contracts	Cash Flow Hedge	MWh		175.0		(2,991.0	)		(2,816.0	)
Forward power contracts	Mark to Market	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 value of cash flow hedges is determined by observable market prices available as of the balance sheet dates and will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges.

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

We also entered into interest rate derivative contracts to manage interest rate exposure related to 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 provide information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended March 31, 2015 and 2014:

	Three months ended						Three months ended
	March 31, 2015						March 31, 2014
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gain in AOCI	$	0.2		$	18.3		$	1.4		$	19.2
Net gains / (losses) associated with current period hedging transactions		0.1			-			(12.9	)		-
Net gains / (losses) reclassified to earnings
Interest expense		-			(0.1	)		-			(0.3	)
Revenues		(0.2	)		-			6.5			-
Purchased power		0.9			-			(0.7	)		-
Ending accumulated derivative gain / (loss) in AOCI	$	1.0		$	18.2		$	(5.7	)	$	18.9
Portion expected to be reclassified to earnings in the next twelve months (a)	$	1.1		$	0.9
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		21			0

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

Mark to Market Accounting

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

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

Regulatory Assets and Liabilities

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

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The following tables present the amount and classification within the Condensed Consolidated Statements of Operations or Condensed Consolidated Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three months ended March 31, 2015 and 2014.

For the three months ended March 31, 2015
$ in millions	Heating Oil			FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	0.1		$	0.9		$	(2.9	)	$	0.1		$	(1.8	)
Realized loss		(0.1	)		(0.1	)		(2.3	)		(0.1	)		(2.6	)
Total	$	-		$	0.8		$	(5.2	)	$	-		$	(4.4	)
Recorded in Income Statement: gain / (loss)
Purchased power		-			0.8			(4.9	)		-			(4.1	)
Revenue		-			-			(0.3	)		-			(0.3	)
Total	$	-		$	0.8		$	(5.2	)	$	-		$	(4.4	)

For the three months ended March 31, 2014
$ in millions	Heating Oil			FTRs			Power			Total
Change in unrealized loss	$	(0.1	)	$	(0.3	)	$	(5.5	)	$	(5.9	)
Realized gain / (loss)		0.1			-			(2.0	)		(1.9	)
Total	$	-		$	(0.3	)	$	(7.5	)	$	(7.8	)
Recorded in Income Statement: loss
Purchased power		-			(0.3	)		(7.5	)		(7.8	)
Fuel		-			-			-			-
Total	$	-		$	(0.3	)	$	(7.5	)	$	(7.8	)

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

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The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged.

Fair Values of Derivative Instruments
at March 31, 2015
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	5.2	$	(2.5)	$	-	$	2.7
Forward power contracts	MTM		4.9		(3.2)		-		1.7
FTRs	MTM		0.3		-		-		0.3
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		3.8		(2.7)		-		1.1
Forward power contracts	MTM		6.4		(0.6)		-		5.8
Total assets		$	20.6	$	(9.0)	$	-	$	11.6
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	4.1	$	(2.5)	$	(1.6)	$	-
Forward power contracts	MTM		13.0		(3.2)		(8.8)		1.0
Heating oil	MTM		0.3		-		(0.3)		-
FTRs	MTM		-		-		-		-
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		2.7		(2.7)		-		-
Forward power contracts	MTM		0.6		(0.6)		-		-
Total liabilities		$	20.7	$	(9.0)	$	(10.7)	$	1.0

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The following table presents the fair value and balance sheet classification of DPL’s derivative instruments at December 31, 2014:

Fair Values of Derivative Instruments
at December 31, 2014
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	5.6	$	(2.0)	$	-	$	3.6
Forward power contracts	MTM		5.5		(3.4)		-		2.1
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		0.3		(0.3)		-		-
Forward power contracts	MTM		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	Cash Flow	$	2.1	$	(2.0)	$	-	$	0.1
Forward power contracts	MTM		7.5		(3.4)		(4.1)		-
FTRs	MTM		0.6		-		-		0.6
Heating oil futures	MTM		0.4		-		(0.4)		-
Natural gas	MTM		0.1		-		(0.1)		-
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		0.6		(0.3)		(0.3)		-
Forward power contracts	MTM		0.9		(0.9)		-		-
Total liabilities		$	12.2	$	(6.6)	$	(4.9)	$	0.7

The aggregate fair value of DPL’s commodity derivative instruments that were in a MTM loss position at March 31, 2015 was $20.7 million. $10.7 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 $9.0 million. Since our debt is below investment grade, we could have to post collateral for the remaining $1.0 million.

9. Contractual Obligations, Commercial Commitments and Contingencies

DPL Inc. – Guarantees

In the normal course of business, DPL enters into various agreements with its wholly owned subsidiaries, DPLE, DPLER and DPLER’s wholly owned subsidiary, MC Squared, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed

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

At March 31, 2015, DPL had $20.5 million of guarantees to third parties for future financial or performance assurance under such agreements: $2.0 million of guarantees on behalf of DPLER, $18.3 million of guarantees on behalf of DPLE and $0.2 million of guarantees on behalf of MC Squared, which will be released upon the April 1, 2015 sale of MC Squared. The guarantee arrangements entered into by DPL with these third parties cover select present and future obligations of DPLE, DPLER and MC Squared to such beneficiaries and are terminable by DPL upon written notice to the beneficiaries within a certain time. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was $2.2 million at March 31, 2015.

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

DP&L – Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in OVEC, an electric generation company, which is recorded using the cost method of accounting under GAAP. As of March 31, 2015, DP&L could be responsible for the repayment of 4.9%, or $74.4 million, of a $1,519.3 million debt obligation that has maturities from 2018 to 2040. This would only happen if OVEC defaulted on its debt payments. As of March 31, 2015, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations

There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Form 10-K for the fiscal year ended December 31, 2014.

Contingencies

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

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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. At March 31, 2015, and December 31, 2014, we had accruals of approximately $0.8 million and $0.8 million, respectively, for environmental matters and other claims. 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, which are disclosed in the paragraphs below. We evaluate the potential liability related to environmental matters quarterly and may revise our accruals. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.

We have several pending environmental matters associated with our EGUs and stations. Some of these matters could have material adverse effects on the operation of the power stations.

National Ambient Air Quality Standards

Effective August 23, 2010, the USEPA implemented its revisions to its primary NAAQS for SO₂ replacing the previous 24-hour standard and annual standard with a one-hour standard. Initial non-attainment designations were made July 25, 2013, and Pierce Township in Clermont County, location of DP&L’s co-owned unit Beckjord Unit 6, was the only area with DP&L operations designated as non-attainment. Beckjord Unit 6 was retired effective October 1, 2014. Non-attainment areas will be required to meet the 2010 standard by October 2018. On April 17, 2014, the USEPA proposed a data requirements rule for air agencies to ascertain attainment characterization more extensively across the country by additional modeling and/or monitoring requirements of areas with sources that exceed specified thresholds of SO₂ emissions. The rule, if finalized, could require the installation of monitors at one or more of DP&L’s coal-fired power plants and result in additional non-attainment designations that could impact our operations. On March 20, 2015, the USEPA informed environmental commissioners of 28 states, including Ohio, that certain areas within their states will be addressed in the next round of designations. The areas will be included if they have monitors that have newly violated the standard, or have areas with a stationary source that had SO₂ emissions greater than a specified level. The designations are to be completed by July 2, 2016. DP&L’s co-owned unit Zimmer meets the criteria for stationary sources. DP&L is unable to determine the effect of these rule changes on its operations.

Carbon Dioxide and Other Greenhouse Gas Emissions

The USEPA issued proposed GHG emissions rules for existing, modified and reconstructed generating units on June 2, 2014. Under the proposed rules, called the Clean Power Plan, states would be judged against state-specific CO₂ emissions targets beginning in 2020, with an expected total U.S. power sector emissions reduction of 30% from 2005 levels by 2030. For Ohio specifically, the Clean Power Plan proposes an interim goal for 2020-2029 and a proposed 2030 final goal of 1,452 pounds of CO₂ per megawatt hour and 1,338 pounds of CO₂ per megawatt hour, respectively, a reduction of approximately 28% from 2012 levels. The proposed rule requires states to submit implementation plans to meet the standards set forth in the rule by June 30, 2016, with the possibility of one- or two-year extensions under certain circumstances. The state plans may focus on energy efficiency improvements at power stations, state renewable portfolio standards, re-dispatch to natural gas combined cycle units and other measures. We could be required, among other things, to make efficiency improvements at our facilities. USEPA expects to finalize this rule by August 1, 2015. We cannot predict the effect of these proposed rules on DP&L’s operations.

Clean Water Act – Regulation of Water Discharge

In December 2006, DP&L submitted a renewal application for the Stuart generating station NPDES permit that was due to expire on June 30, 2007. The Ohio EPA issued a draft permit that was received on November 12, 2008.  In September 2010, the USEPA formally objected to the November 12, 2008, draft permit due to questions regarding the basis for the alternate thermal limitation.  The Ohio EPA issued a draft permit in December 2011 and a public hearing was held on February 2, 2012. The draft permit required DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system.

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DP&L submitted comments to the draft permit. In November 2012, the Ohio EPA issued another draft which included a compliance schedule for performing a study to justify an alternate thermal limitation and to which DP&L submitted comments. In December 2012, the USEPA formally withdrew their objection to the permit. On January 7, 2013, the Ohio EPA issued a final permit. On February 1, 2013, DP&L appealed various aspects of the final permit to the Environmental Review Appeals Commission. A hearing before the Commission is scheduled for August 2015. Depending on the outcome of the appeal process, the effects on DP&L’s operations could be material.

Regulation of Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site.  In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach.  In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS.  No recent activity has occurred with respect to that notice or PRP status.  On August 16, 2006, an Administrative Settlement Agreement and Order on Consent (“ASAOC”) was executed and became effective among a group of PRPs, not including DP&L, and the USEPA.  On August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site.  DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010.  On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio (the “District Court”) against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site.  On February 10, 2011, the District Court Judge dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination.  The District Court Judge, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck to the landfill.  Discovery, including depositions of past and present DP&L employees, was conducted in 2012.  On February 8, 2013, the District Court Judge granted DP&L’s motion for summary judgment on statute of limitations grounds with respect to claims seeking a contribution toward the costs that are expected to be incurred by the PRP group in performing an RI/FS under the August 15, 2006 ASAOC.  That summary judgment ruling was appealed on March 4, 2013, and on July 14, 2014, a three-judge panel of the U.S. Court of Appeals for the 6^th Circuit affirmed the lower Court’s ruling and subsequently denied a request by the plaintiffs for rehearing.  On November 14, 2014, the PRP group appealed the decision to the U.S. Supreme Court, but the writ of certiorari was denied by the Court on January 20, 2015.  On April 5, 2013, the PRP group entered into a second ASAOC relating primarily to vapor intrusion under some of the buildings at the South Dayton Dump landfill site.  On April 13, 2013, as amended July 30, 2013, the PRP group filed another civil complaint against DP&L and numerous other defendants alleging that each defendant contributed to the contamination of the site by delivering hazardous waste to the site or by releasing hazardous waste on other sites that migrated to the landfill site.  On February 18, 2014, after considering various motions and alternative grounds to dismiss, the District Court Judge dismissed some of the alleged grounds for relief that the PRP group had made, but ruled in the PRP group’s favor with respect to motions to dismiss the case in its entirety finding, among other things, that the 2013 ASAOC involved a different scope of work and thus the contributions sought were not seeking the same remedy that had been dismissed in the first civil suit.  Appeals from this ruling are pending before the 6^th Circuit Court of Appeals.  On January 14, 2015, the PRP group served DP&L and other defendants a request for production of documents related to any survey regarding waste management or waste disposal.  Information responsive to this request was provided on February 17, 2015.  In addition, on January 16, 2015, the USEPA issued a Special Notice Letter and Section 104(e) Information Request to DP&L and other defendants, requesting historical information related to waste management practices.  DP&L responded to this request on March 27, 2015.  DP&L is unable to predict the outcome of this action by the plaintiffs and USEPA.  Additionally, the District Court’s 2013 ruling and the Court of Appeals’ affirmation of that ruling in 2014 does not address future litigation that may arise with respect to actual remediation costs.  While DP&L is unable to predict the outcome of these matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.

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Regulation of Ash Ponds

There has been increasing advocacy to regulate coal combustion residuals (CCR) under the Resource Conservation Recovery Act (RCRA). On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion byproducts including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. The USEPA released its final rule on December 19, 2014, designating coal combustion residuals that are not beneficially reused as non-hazardous solid waste under RCRA Subtitle D. The rule was published in the Federal Register on April 17, 2015 and becomes effective October 19, 2015, and applies new detailed management practices to new and existing landfills and surface impoundments, including lateral expansions of such units. DP&L is currently reviewing the rule and assessing the impact on our operations. Our business, financial condition or operations could be materially and adversely affected by this regulation.

10. Business Segments

DPL operates through two segments; Utility and Competitive Retail. The Utility segment consists of the operations of DPL’s subsidiary, DP&L. The Competitive Retail segment consists of DPL’s wholly owned subsidiary DPLER, including DPLER’s wholly owned subsidiary, MC Squared. This is how we view our business and make decisions on how to allocate resources and evaluate performance.

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and sell electricity to residential, commercial, industrial and governmental customers. DP&L generates electricity at five coal-fired power plants and DP&L distributes power to more than 516,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L also sells electricity to DPLER and any excess energy and capacity is sold into the PJM wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.

The Competitive Retail segment is comprised of the DPLER and MC Squared competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or MC Squared as their alternative electric supplier. As of March 31, 2015, the Competitive Retail segment sold electricity to approximately 259,000 customers located throughout Ohio and in Illinois. This number includes approximately 116,000 customers in Northern Illinois of MC Squared, a Chicago-based retail electricity supplier. On April 1, 2015, DPLER closed on the sale of MC Squared to Chicago-based Wolverine. After considering the sale of MC Squared on April 1, 2015, the Competitive Retail segment sold electricity to 143,000 customers. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L. The majority of intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customer; the price approximates market prices for wholesale power at the inception of each customer’s contract. The Competitive Retail segment has no transmission or generation assets. The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.

Included in the “Other” column in the following tables are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs including 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.

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

$ in millions	Utility		Competitive Retail		Other			Adjustments and Eliminations			DPL Consolidated
For the three months ended March 31, 2015
Revenues from external customers	$	350.6	$	122.3	$	21.6		$	-		$	494.5
Intersegment revenues		110.7		-		1.6			(112.3	)		-
Total revenues		461.3		122.3		23.2			(112.3	)		494.5
Fuel		69.3		-		7.1			-			76.4
Purchased power		189.7		111.7		4.2			(111.4	)		194.2
Gross margin	$	202.3	$	10.6	$	11.9		$	(0.9	)	$	223.9
Depreciation and amortization	$	34.7	$	0.3	$	-		$	-		$	35.0
Interest expense		8.7		-		21.9			(0.1	)		30.5
Income tax expense (benefit)		14.8		1.3		(3.4	)		-			12.7
Net income / (loss)		36.5		1.6		(9.4	)		-			28.7
Cash capital expenditures	$	33.1	$	0.2	$	0.4		$	-		$	33.7
At March 31, 2015
Total assets	$	3,289.7	$	72.3	$	1,476.1		$	(1,284.2	)	$	3,553.9

$ in millions	Utility		Competitive Retail			Other			Adjustments and Eliminations			DPL Consolidated
For the three months ended March 31, 2014
Revenues from external customers	$	292.6	$	148.4		$	19.2		$	0.1		$	460.3
Intersegment revenues		139.5		-			1.0			(140.5	)		-
Total revenues		432.1		148.4			20.2			(140.4	)		460.3
Fuel		84.3		-			5.7			-			90.0
Purchased power		168.0		140.2			5.4			(139.5	)		174.1
Amortization of intangibles		-		-			0.3			-			0.3
Gross margin	$	179.8	$	8.2		$	8.8		$	(0.9	)	$	195.9
Depreciation and amortization	$	36.5	$	0.1		$	(1.4	)	$	0.1		$	35.3
Goodwill impairment		-		-			135.8			-			135.8
Fixed-asset impairment		-		-			11.5			-			11.5
Interest expense		7.8		0.1			23.1			(0.2	)		30.8
Income tax expense (benefit)		4.0		(0.7	)		95.4			0.1			98.8
Net income / (loss)		9.4		(1.4	)		(257.0	)		-			(249.0	)
Cash capital expenditures	$	27.4	$	-		$	1.0		$	-		$	28.4
At December 31, 2014
Total assets	$	3,338.7	$	94.9		$	1,440.1		$	(1,295.9	)	$	3,577.8

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11. Goodwill Impairment

During the first quarter of 2014, we performed an interim impairment test on the $135.8 million in goodwill at our DPLER reporting unit. The DPLER reporting unit was identified as being "at risk" during the fourth quarter of 2013. The impairment indicators arose based on market information available regarding actual and proposed sales of competitive retail marketers, which indicated a significant decline in valuations during the first quarter of 2014. In Step 1 of the interim impairment test, the fair value of the reporting unit was determined to be less than its carrying amount under both the market approach and the income approach using a discounted cash flow valuation model. The significant assumptions included commodity price curves, estimated electricity to be demanded by its customers, changes in its customer base through attrition and expansion, discount rates, the assumed tax structure and the level of working capital required to run the business. 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.

12. Fixed-asset Impairment

During the first quarter of 2014, DP&L 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. DP&L 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. In May 2014, an agreement was signed for the sale of DP&L’s interest in the generating assets at East Bend. The sale price approximated the carrying value. This transaction closed on December 30, 2014.

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DPL INC.

Offer to Exchange
6.75% Senior Notes due 2019
for
New 6.75% Senior Notes Due 2019

Until September 13, 2015 all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus.  This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters with respect to their unsold allotments or subscriptions.

PROSPECTUS

June 15, 2015