Rule 424(b)(3)
Registration No. 333-195315

PROSPECTUS

The Dayton Power and Light Company

Offer to Exchange

First Mortgage Bonds, 1.875% Series due 2016
(registered)

for its

First Mortgage Bonds, 1.875% Series due 2016
(unregistered)

We are offering to exchange up to $445,000,000 of our new registered First Mortgage Bonds, 1.875% Series due 2016 (CUSIP No. 240019 BS7) (the “New Bonds”) for up to $445,000,000 of our existing unregistered First Mortgage Bonds, 1.875% Series due 2016 (CUSIP Nos. 240019 BR9 and U23926 AA3) (the “Old Bonds”). The terms of the New Bonds are identical in all material respects to the terms of the Old Bonds, except that the New Bonds 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 Bonds do not apply to the New Bonds. The New Bonds will represent the same debt as the Old Bonds and we will issue the New Bonds under the same indenture.

To exchange your Old Bonds for New Bonds:

•

you are required to make the representations described on page 69 to us; and

•

you should read the section called “The Exchange Offer” starting on page 69 for further information on how to exchange your Old Bonds for New Bonds.

The exchange of the Old Bonds for New Bonds in the exchange offer will not be a taxable transaction for United States federal income tax purposes. See the discussion under the caption “Certain United States Federal Income Tax Considerations” for more information regarding the tax consequences to you of the exchange offer.

The exchange offer will expire at 11:59 P.M. New York City time on July 14, 2014 unless it is extended.

See “Risk Factors” beginning on page 5 of this prospectus for a discussion of risk factors that should be considered by you prior to tendering your Old Bonds 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 16, 2014

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TABLE OF CONTENTS

	Page
SUMMARY		1
RISK FACTORS		5
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		16
USE OF PROCEEDS		17
RATIO OF EARNINGS TO FIXED CHARGES		18
CAPITALIZATION		19
SELECTED FINANCIAL AND OTHER DATA		20
MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION		21
BUSINESS		48
DESCRIPTION OF THE NEW BONDS		61
THE EXCHANGE OFFER		69
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS		76
PLAN OF DISTRIBUTION		77
VALIDITY OF SECURITIES		78
EXPERTS		78
WHERE YOU CAN FIND MORE INFORMATION		79
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 New Bonds, including the merits and risks involved.

We are not making any representation to any purchaser of the New Bonds regarding the legality of an investment in the New Bonds 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 New Bonds.

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 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 this new AEP subsidiary, effective January 1, 2014.
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
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 Company, a unit of Chicago-based Exelon Corporation
CRES	Competitive Retail Electric Service
CSAPR	Cross-State Air Pollution Rule
Dark spread	A common metric used to estimate returns over fuel costs of coal-fired electric generating units
DPL	DPL Inc.
DPLE	DPL Energy, LLC, a wholly-owned subsidiary of DPL that owns and operates peaking generation facilities from which it makes wholesale sales
DPLER	DPL Energy Resources, Inc., a wholly-owned subsidiary of DPL that 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 that delivers electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio.
Duke Energy	Duke Energy Ohio, Inc., formerly The Cincinnati Gas & Electric Company (CG&E)
EBITDA	Earnings before interest, taxes, depreciation and amortization
EGU	Electric generating unit
EIR	Environmental Investment Rider
EPS	Earnings Per Share
ESOP	Employee Stock Ownership Plan
ESP	Electric Security Plans filed with the PUCO pursuant to Ohio law
2009 ESP Stipulation	A Stipulation and Recommendation filed with the PUCO on February 24, 2009 regarding DP&L’s ESP filing pursuant to SB 221. The Stipulation was signed by the Staff of the PUCO, the OCC and various intervening parties. The PUCO approved the Stipulation on June 24, 2009.
ESSS	PUCO Electric Service and Safety Standards
FASB	Financial Accounting Standards Board
FASC	FASB Accounting Standards Codification

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Abbreviation or Acronym	Definition
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
kWh	Kilowatt hours
Master Trusts	DP&L established Master Trusts to hold assets that could be used for the benefit of employees participating in employee benefit plans
MC Squared	MC Squared Energy Services, LLC, a retail electricity supplier wholly-owned by DPLER
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
MRO	Market Rate Option, a plan available to be filed with the PUCO pursuant to Ohio law
MTM	Mark to Market
MVIC	Miami Valley Insurance Company, a wholly-owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries and, in some cases, insurance services to partner companies related to jointly-owned facilities operated by DP&L
MW	Megawatt
MWh	Megawatt hour
NERC	North American Electric Reliability Corporation
Non-bypassable	Charges that are assessed to all customers regardless of whom the customer selects to supply its retail electric service
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
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

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Abbreviation or Acronym	Definition
Predecessor	DPL prior to the Merger date
PRP	Potentially Responsible Party
PUCO	Public Utilities Commission of Ohio
RPM	Reliability Pricing Model. 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.
RSU	Restricted Stock Unit
RTO	Regional Transmission Organization
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
SERP	Supplemental Executive Retirement Plan
Service Company	AES US Services, LLC, the shared services affiliate providing accounting, finance, and other support services to AES’ US SBU businesses
SFAS	Statement of Financial Accounting Standards
SO₂	Sulfur Dioxide
SO₃	Sulfur Trioxide
SSO	Standard Service Offer represents regulated rates, authorized by the PUCO, charged to DP&L retail customers that take retail generation service from DP&L within DP&L’s service territory
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 – Non-bypassable
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 Bonds for New Bonds, including the section entitled “Risk Factors” beginning on page 5 of this prospectus.

Unless otherwise indicated or the context otherwise requires, the terms “DP&L,” we,” “our,” “us,” and “the Company” refer to The Dayton Power and Light Company.

Our Company

General

The Dayton Power and Light Company (“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. We have the exclusive right to provide such service to our more than 516,000 customers located in West Central Ohio. Additionally, we offer retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generate electricity at seven coal-fired power stations. Beginning in 2014, we are required to source 10% of the generation for our SSO customers through a competitive bid process. Principal industries located in our service territory include automotive, food processing, paper, plastic, manufacturing and defense. Our sales reflect the general economic conditions, seasonal weather patterns of the area and the market price of electricity. We sell any excess energy and capacity into the wholesale market. We also sell electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER’s retail customers.

On March 19, 2014, the PUCO issued a second entry on rehearing which shortened the time by which we must divest our generation assets to no later than January 1, 2016, terminated the potential extension of the SSR on April 30, 2017 instead of May 31, 2017, and accelerated our phase-in of the competitive bidding structure to 10% in 2014, 60% in 2015 and 100% in 2016. Parties, including us, have filed applications for rehearing on this Commission Order that are currently pending.

Our electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while our generation business is deemed competitive under Ohio law. Accordingly, we apply the accounting standards for regulated operations to our electric transmission and distribution businesses and record 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.

As of March 31, 2014, we employed approximately 1,189 people. All of our outstanding shares of common stock are held by DPL Inc. (“DPL”), which became our corporate parent, effective April 21, 1986. Our ultimate parent is The AES Corporation (“AES”). Our principal executive and business office is located at 1065 Woodman Drive, Dayton, Ohio 45432 — telephone (937) 224-6000.

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The Exchange Offer

Securities Offered

We are offering up to $445,000,000 aggregate principal amount of new First Mortgage Bonds, 1.875% Series due 2016 (the “New Bonds”), which will be registered under the Securities Act.

The Exchange Offer

We are offering to issue the New Bonds in exchange for a like principal amount of your Old Bonds. We are offering to issue the New Bonds to satisfy our obligations contained in the registration rights agreement entered into when the Old Bonds 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 14, 2014 unless it is extended. If you decide to exchange your Old Bonds for New Bonds, you must acknowledge that you are not engaging in, and do not intend to engage in, a distribution of the New Bonds. If you decide to tender your Old Bonds in the exchange offer, you may withdraw them at any time prior to July 14, 2014. If we decide for any reason not to accept any Old Bonds for exchange, your Old Bonds will be returned to you without expense to you promptly after the exchange offer expires. You may only exchange Old Bonds in denominations of $1,000 and integral multiples of $1,000 in excess thereof.

Certain United States Federal Income Tax Considerations

Use of Proceeds

We will not receive any proceeds from the issuance of the New Bonds in the exchange offer.

Exchange Agent

The Bank of New York Mellon is the exchange agent for the exchange offer.

Failure to Tender Your Old Bonds

If you fail to tender your Old Bonds 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 Bonds or to pay you additional interest or liquidated damages. All untendered Old Bonds will continue to be subject to the restrictions on transfer set forth in the Old Bonds and in the indenture. In general, the Old Bonds 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 applicable state securities laws. We do not currently anticipate that we will register such untendered Old Bonds under the Securities Act and, following this exchange offer, will be under no obligation to do so.

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You will be able to resell the New Bonds 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 Bonds issued in exchange for the Old Bonds in the exchange offer may be offered for resale, resold or otherwise transferred by you without registering the New Bonds 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 Bonds 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 Bonds; and

•

you are not engaged in, and do not intend to engage in, a distribution of the New Bonds.

If you are an affiliate of DP&L, or you are engaged in, intend to engage in or have any arrangement or understanding with respect to, the distribution of New Bonds 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 Bonds for your own account in the exchange offer:

•

you must represent that you do not have any arrangement with us or any of our affiliates to distribute the New Bonds;

•

you must acknowledge that you will deliver a prospectus in connection with any resale of the New Bonds 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 Bonds received in exchange for Old Bonds 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 New Bonds

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

Issuer

The Dayton Power and Light Company.

Bonds Offered

$445,000,000 aggregate principal amount of New Bonds.

Maturity

The New Bonds will mature on September 15, 2016, unless redeemed prior to that date.

Interest Rate

The New Bonds will bear interest at 1.875% per annum.

Interest Payment Dates

March 15 and September 15 of each year, commencing on September 15, 2014.

Optional Redemption

We may redeem the New Bonds, in whole or in part, at our option at any time or from time to time prior to maturity, at a redemption price equal to the Make-Whole Amount (as defined below) plus accrued and unpaid interest to the redemption date. The Make-Whole Amount equals the greater of (i) 100% of the principal amount of the New Bonds being redeemed or (ii) as determined by a Quotation Agent (as defined below) as of the redemption date, the sum of the present value of the scheduled payments of principal and interest on the New Bonds from the redemption date to the stated maturity date of the New Bonds (excluding the portion of any such interest accrued to such redemption date), discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at a discount rate equal to the Treasury Rate (as defined below) plus 20 basis points. See “Description of the New Bonds—Optional Redemption.”

Ranking

The New Bonds will be senior secured obligations of the Issuer, ranking equally in right of payment with our other existing or future first mortgage bonds issued under the First and Refunding Mortgage, dated as of October 1, 1935, between us and the Bank of New York Mellon, as trustee, as amended (the “Mortgage”). See “Description of the New Bonds—Priority and Security.”

Security

The New Bonds will be secured by the assets of the Issuer that are currently mortgaged pursuant to the existing Mortgage. See “Description of the New Bonds—Priority and Security.”

Book-Entry Form

The New Bonds will be issued in registered book-entry form represented by one or more global bonds to be deposited with or on behalf of The Depository Trust Company (“DTC”) or its nominee. Transfers of the New Bonds will be effected only through the facilities of DTC. Beneficial interests in the global bonds may not be exchanged for certificated bonds except in limited circumstances. See “Book-Entry, Delivery and Form.”

Trustee, Registrar and Paying Agent

The Bank of New York Mellon.

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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 Bonds in the exchange offer, the transfer restrictions currently applicable to your Old Bonds will remain in force and the market price of your Old Bonds could decline.

If you do not exchange your Old Bonds for New Bonds in the exchange offer, then you will continue to be subject to the transfer restrictions on the Old Bonds as set forth in the offering memorandum distributed in connection with the private offering of the Old Bonds. In general, the Old Bonds 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 Bonds, we do not intend to register resales of the Old Bonds under the Securities Act. The tender of Old Bonds under the exchange offer will reduce the principal amount of the Old Bonds outstanding, which may have an adverse effect upon, and increase the volatility of, the market price of the Old Bonds due to reduction in liquidity.

You must follow the exchange offer procedures carefully in order to receive the New Bonds.

If you do not follow the procedures described in this prospectus, you will not receive any New Bonds. If you want to tender your Old Bonds in exchange for New Bonds, you should allow sufficient time to ensure timely delivery. No one is under any obligation to give you notification of defects or irregularities with respect to tenders of Old Bonds 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 Bonds.

In order to comply with the securities laws of certain jurisdictions, the New Bonds 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 Bonds 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 New Bonds

We have significant debt, and may not maintain our current credit ratings.

We have a significant amount of debt. Our credit ratings may in the future be lower than our current or historical credit ratings. Differences in credit ratings would affect the interest rates charged on financings, as well as the amounts of indebtedness, types of financing structures and debt markets that may be available to us. A downgrade to our existing credit ratings could have a material adverse effect on our operating results and our ability to obtain additional financing, which could adversely affect the market value of the New Bonds and could impair our ability to pay interest or principal on the New Bonds.

Ratings of the New Bonds may change after issuance and affect the market price and marketability of the New Bonds.

Bond ratings are limited in scope and do not address all material risks relating to an investment in the New Bonds, but rather reflect only the view of each rating agency at the time the rating is issued. An explanation of the significance of a rating may be obtained from the rating agency. There is no assurance that any particular credit ratings will be issued or remain in effect for any given period of time or that such ratings will not be downgraded, suspended or withdrawn entirely by the rating agencies, if, in each rating agency’s judgment, circumstances so warrant. Holders of New Bonds will have no recourse against us in the event of a change in or suspension or withdrawal of such ratings. Any downgrade, suspension or withdrawal of such ratings may have an adverse effect on the market price or marketability of the New Bonds.

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The New Bonds are not listed on any securities exchange and a liquid market for the New Bonds may not develop or be maintained.

We have not listed and we do not intend to list the New Bonds on any national securities exchange or to seek their quotation on any automated dealer quotation system. We cannot assure holders of the New Bonds that any liquid market for the New Bonds will develop or be maintained. Further, there can be no assurance as to the liquidity of any market that may develop for the New Bonds, holders’ ability to sell their New Bonds or the price at which holders will be able to sell their New Bonds. Future trading prices of the New Bonds will depend on many factors, including prevailing interest rates, our financial condition and results of operations, the then-current ratings assigned to the New Bonds and the market for similar securities. Any trading market that develops would be affected by many factors independent of and in addition to the foregoing, including the time remaining to the maturity of the New Bonds, the outstanding amount of the New Bonds, the daily trading volume of the New Bonds and the level, direction and volatility of market interest rates generally.

We may choose to redeem the New Bonds prior to maturity.

We may redeem the New Bonds at any time in whole, or from time to time in part, at a redemption price equal to the Make-Whole-Amount plus accrued and unpaid interest to the redemption date. If prevailing interest rates are lower at the time of redemption, holders of the New Bonds may not be able to reinvest the redemption proceeds in a comparable security at an interest rate as high as the interest rate on the New Bonds being redeemed. Our redemption right may also adversely affect holders’ ability to sell their New Bonds. See “Description of the New Bonds—Optional Redemption.”

The collateral securing the New Bonds might not be sufficient to satisfy all the obligations secured by the collateral.

Our obligations under the New Bonds are secured by the Mortgage. The Mortgage is also for the benefit of all holders of other series of our first mortgage bonds. See “Description of the New Bonds—Priority and Security.” As of December 31, 2013, including the Old Bonds, we had approximately $859.4 million aggregate principal amount of first mortgage bonds outstanding. The value of the Mortgage in the event of a liquidation will depend upon market and economic conditions, the availability of buyers, and similar factors. No independent appraisals of any of the mortgaged property have been prepared by us or on our behalf in connection with this exchange offer. Since no appraisals have been performed in connection with this exchange offer, we cannot assure you that the proceeds of any sale of the mortgaged assets following an acceleration of maturity of the New Bonds would be sufficient to satisfy amounts due on the New Bonds and the other debt secured by the mortgaged assets.

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.

On September 6, 2013, as a part of its ESP order, the PUCO ordered us to file a revised Corporate Separation Plan by December 31, 2013 and to complete the separation of our generation business on or before May 31, 2017. We filed a generation separation application with the PUCO at the end of December 2013, as required in the ESP order, and on February 25, 2014, filed a supplemental application. In the supplemental application, we reaffirmed our commitment to separate the generation assets on or before May 31, 2017. We continue to look at multiple options to effectuate the separation including the transfer to an unregulated affiliate or through a sale process. 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. Several regulatory 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, including agreements governing our debt.

Risks Related to Our Business

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 our service territory. DPLER, a wholly-owned subsidiary of DPL, is one of those PUCO-certified CRES providers. Unaffiliated CRES providers also have been certified to provide energy in our service territory. Customer switching from us to DPLER reduces our revenues. Increased competition by unaffiliated CRES providers in our

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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 could have a material adverse effect on our results of operations, financial condition and cash flows. 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.

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, 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.

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 our rate structure and the ability to recover certain costs which will affect our results of operations, cash flows and financial condition. Our ESP and certain filings made by us in connection with this plan are further discussed under “Ohio Retail Rates” in “Business–Competition and Regulation.”

In Ohio, retail generation rates are no longer subject to cost-based regulation, the distribution and transmission businesses are still regulated. While 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 we receive may or may not match our expenses at any given time. Therefore, we are subject to prevailing market prices for electricity and would not necessarily be able to charge rates that produce timely or full recovery of our expenses. Changes in, or reinterpretations of, the laws, rules, policies and procedures that set electric rates, permitted rates of return, changes in our 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.

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

SB 221 contains targets relating to advanced energy, renewable energy, peak demand reduction and energy efficiency standards. The standards require that, by the year 2025 and each year thereafter, 25% of the total number of kWh of electricity sold by the utility to retail electric consumers must come from alternative energy resources. These include “advanced energy resources” such as distributed generation, clean coal, advanced nuclear, energy efficiency and fuel cell technology; and “renewable energy resources” such as solar, hydro, wind, geothermal and biomass. At least half of the 25% must be generated from renewable energy resources, including solar energy. Annual renewable energy standards began in 2009 with increases in required percentages each year through 2024. The advanced energy standard must be met by 2025 and each year thereafter. 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 advanced energy and renewable energy standards have increased our power supply costs and are expected to continue to increase (and could materially increase) these costs. We are entitled to recover costs associated with our alternative energy compliance costs, as well as our energy efficiency and demand response programs. We 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.

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, we use a variety of non-derivative and derivative instruments, such as swaps, futures and forwards, to manage our market risks. We also use 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 have a material adverse effect on our results of operations, financial condition and cash flows.

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, we have a significant portion of the expected coal volume needed under contract to meet our retail and wholesale sales requirements for 2014. In 2013, approximately 80% of our coal for stations we operate was provided by four suppliers, one of which was under a contract in excess of one year. 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

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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, we are a co-owner of certain generation facilities where we are a non-operating owner. We do not procure or have control over the fuel for these facilities, but we are responsible for our 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 our total cost. We 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. 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.

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.

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 NOx, 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, 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 Station, we are also subject to continuing compliance requirements related to NOx, SO₂ and particulate matter emissions under our 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. We own a non-controlling interest in several generating stations operated by our co-owners. As a non-controlling owner in these generating stations, we are responsible for our pro rata share of expenditures for complying with environmental laws, regulations and other requirements, but have limited control over the compliance measures taken by our co-owners. 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

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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.

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. Our inability to fully or timely recover such costs associated with climate change 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.

We sell 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.

We may sell our excess emission allowances, including NOx 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 CAIR or any replacement rule. These factors could cause the amount and price of excess emission allowances we sell 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 NOx 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 our emission allowance sales.

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.

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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 over 50% 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. We have constructed and placed into service FGD facilities at most of 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, at other stations, 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 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.

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, we are 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, we are 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 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 we are permitted to seek recovery of storm damage costs under our ESP, if we are 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.

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, we turned over control of our 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

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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, RTO-related costs associated with serving SSO load are being recovered through our SSO retail rates. If in the future, however, we are unable to recover all of these costs in a timely manner, and since the SSO retail riders are 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, we 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 us and DPLE. These amounts could be significant and 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 us 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. We are recovering the Ohio retail jurisdictional share of these allocated costs from our SSO retail customers through the TCRR rider. To the extent that any costs in the future are material and we are unable to recover them from our customers, it could have a material adverse effect on our results of operation, 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. We have 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 currently maintain both cash on deposit and investments in cash equivalents 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

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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.

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

We 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 currently 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.

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.

Our 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 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.

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Overall lower prices in the retail electricity market have led to increased switching from us to other CRES providers, including DPLER, who are offering retail prices lower than our current SSO. Also, several municipalities in our 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 our 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.

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 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 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 Financial Statements and we will continue to monitor the development of the potential implementation of IFRS.

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

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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 business.

Over half of our employees are represented by a collective bargaining agreement that is in effect until October 31, 2014. 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 business.

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.

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

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 Financial Statements, which are included in this prospectus, 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;

•

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 are subject;

•

the development and operation of RTOs, including PJM to which we have given control of our 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;

•

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

•

general economic conditions; and

•

and the risks and other factors discussed 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.

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USE OF PROCEEDS

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

The net proceeds from the sale of the Old Bonds were approximately $436.7 million, after deduction of the initial purchasers’ discounts and commissions and other expenses of the offering. On October 1, 2013, we used the net proceeds of the Old Bonds, along with cash on hand, to repay all of the $470.0 million aggregate principal amount of our First Mortgage Bonds, 5.125% Series due 2013.

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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, 2014		Year Ended December 31,
	Three Months Ended March 31, 2014		2013		2012		2011		2010		2009
Ratio of earnings to fixed charges		2.7		3.6		4.5		8.2		11.4		10.1

The Ratio of Earnings to Fixed Charges represents, on a pre-tax basis, the number of times earnings cover fixed charges. Earnings consists of income before extraordinary items adding back fixed charges and the provision for income taxes. Fixed charges consists of interest on long-term debt, other interest expense and an estimate of the interest portion of all rentals charged to income.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of March 31, 2014:

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

	As of March 31, 2014
	(In millions)
Cash and cash equivalents	$	3.2

Current portion of long-term debt	$	0.2
Long-term debt:
Unsecured revolving credit facility		0.4
Pollution control series maturing in January 2028 - 4.7%⁽¹⁾		35.3
Pollution control series maturing in January 2034 - 4.8%⁽¹⁾		179.1
Pollution control series maturing in September 2036 - 4.8%⁽¹⁾		100.0
Pollution control series maturing in November 2040 - variable rate⁽¹⁾		100.0
U.S. Government note maturing in February 2061 - 4.2%		18.2
Old Bonds⁽¹⁾		445.0
Total long-term debt		878.2
Redeemable preferred stock		22.9
Total common shareholder’s equity		1,206.3
Total capitalization	$	2,107.4

(1)

Each pollution control series and the Old Bonds represents a series of first mortgage bonds that are secured by the same collateral securing the New Bonds offered hereby.

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SELECTED FINANCIAL AND OTHER DATA

The table below presents our selected historical 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 financial statements and related notes included herein.

The selected historical statement of operations and other operating data for each of the years ended December 31, 2013, 2012 and 2011 and the balance sheet data as of December 31, 2013 and 2012 are derived from our audited financial statements included herein. The selected historical statement of operations and other operating data for each of the three months ended March 31, 2014 and 2013 are derived from our unaudited condensed financial statements included herein. Our historical results for any prior period are not necessarily indicative of results to be expected for any future period.

	Three Months Ended March 31,				Year Ended December 31,
	2014		2013		2013		2012		2011		2010		2009
					(In millions)
Income Statement Data:
Total revenues		432.1		376.5	$	1,551.5	$	1,531.8	$	1,677.7	$	1,738.8	$	1,500.8
Operating income		21.5		49.6	$	142.4	$	185.0	$	319.9	$	450.2	$	421.9
Net income		9.4		30.2	$	83.6	$	91.2	$	193.2	$	277.7	$	258.9

Other Operating Data:
Electric sales (millions of kWh)		5,314		4,480		19,423		15,606		15,599		17,083		16,590

	As of March 31, 2014		As of December 31,
	As of March 31, 2014		2013		2012		2011		2010		2009
	(In millions)		(In millions)
Balance Sheet Data:
Cash and cash equivalents	$	3.2	$	22.9	$	28.5	$	32.2	$	54.0	$	57.1
Total assets	$	3,343.1	$	3,313.1	$	3,464.2	$	3,538.3	$	3,475.4	$	3,457.4
Long-term debt (including current portion)	$	877.1	$	877.1	$	903.1	$	903.4	$	884.1	$	884.3
Redeemable preferred stock	$	22.9	$	22.9	$	22.9	$	22.9	$	22.9	$	22.9

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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

We are primarily engaged in the generation, transmission and distribution of electricity in West Central Ohio and the sale of energy to DPLER in Ohio and Illinois. 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, 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.”

The following discussion should be read in conjunction with the accompanying Financial Statements and related footnotes.

REGULATORY ENVIRONMENT

Our 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. In 2007, a U.S. Supreme Court decision upheld that the USEPA has the authority to regulate GHG emissions under the CAA. In April 2009, the USEPA issued a proposed endangerment finding under the CAA. The proposed finding determined that CO₂ and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. This endangerment finding became effective in January 2010.

Various industry groups and states petitioned the U.S. Supreme Court to review the D.C. Circuit Court’s recent decision to uphold the USEPA’s endangerment finding and certain GHG regulations based on that endangerment finding. On October 15, 2013, the U.S. Supreme Court agreed to review several related cases addressing the USEPA’s authority to issue GHG Prevention of Significant Deterioration permits under Section 165 of the CAA. As a result of the endangerment finding and other USEPA regulations, emissions of CO₂ and other GHGs from EGUs and other stationary sources are subject to regulation. Increased pressure for GHG emissions reduction is also coming from

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investor organizations and the international community. Environmental advocacy groups are also focusing considerable attention on GHG emissions from power generation facilities and their potential role in climate change. Approximately 99% of the energy we produce is generated by coal. Our share of CO₂emissions 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 us of such controls could be material.

Clean Water Act

In April 2012, we received an NOV related to the construction of the Carter Hollow landfill at the Stuart Station. The NOV indicated that construction activities caused sediment to flow into downstream creeks. We are in the process of resolving this NOV with the Ohio EPA. In addition, the U.S. Army Corps of Engineers (the “Corps”) issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill. We installed sedimentation ponds as part of the runoff control measures to address this issue and worked with the various agencies to resolve their concerns. In March 2013, we received a proposed Administrative Order from the USEPA which, after negotiation of the terms and conditions, was signed by our management on May 30, 2013. A final Consent Agreement and Final Order was executed on July 8, 2013 and the previously issued permit was reinstated by the Corps on October 29, 2013.

NOx and SO₂ Emissions − CSAPR

The CAIR final rules were published on May 12, 2005. CAIR created an interstate trading program for annual NO_x emission allowances and made modifications to an existing trading program for SO₂. Litigation brought by entities not including us resulted in a decision by the U.S. Court of Appeals for the District of Columbia Circuit on July 11, 2008 to vacate CAIR and its associated Federal Implementation Plan. On December 23, 2008, the U.S. Court of Appeals issued an order on reconsideration that permits CAIR to remain in effect until the USEPA issues new regulations that would conform to the CAA requirements and the Court’s July 2008 decision.

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 and CAIR being reinstated pending the promulgation of a replacement rule. On December 10, 2013, the U.S. Supreme Court heard oral arguments as part of its review of the decision to vacate CSAPR. The Ohio EPA has a State Implementation Plan (the “Ohio SIP”) that incorporates the CAIR program requirements, which remain in effect pending judicial review of CSAPR. If reinstated, we do not believe CSAPR will have a material effect on our operations, but we are unable to estimate the affect of any replacement requirements, if promulgated, in future years.

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, also directed the USEPA to issue new standards, regulations, or guidelines, as appropriate, that address CO₂ emissions from existing power plants. The President directed the USEPA to (i) issue a proposed rule by June 1, 2014; (ii) issue a final rule by June 1, 2015; and (iii) require that States submit their implementation plans to the USEPA by no later than June 30, 2016. Following this announcement, in September 2013, 18 states, including Ohio, sent the USEPA a white paper questioning the USEPA’s legal authority to impose CO₂emission standards on existing power plants. It is too soon to determine whether any such standards would materially impact our operations.

It is impossible to estimate the impact and compliance costs associated with any future USEPA GHG regulations applicable to new, modified or existing EGUs until such regulations are finalized; however, 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 contain targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards. The standards require that, by the year 2025, 25% of the total number of kWh of electricity sold by the utility to retail electric consumers must come from alternative energy

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resources, which include “advanced energy resources” such as distributed generation, clean coal, advanced nuclear, energy efficiency and fuel cell technology; and “renewable energy resources” such as solar, hydro, wind, geothermal and biomass. At least half of the 25% must be generated from renewable energy resources, including 0.5% from solar energy. 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. Pursuant to the ESP Stipulation, we were subject to the SEET in 2013 based on 2012 earnings results, which did not have a material impact. Through the ESP Order the PUCO established our 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 requires 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.

On October 5, 2012, we 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 is 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 our 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 (the “ESP Order”).

The ESP Order stated that our next ESP would begin January 2014 and extends through May 31, 2017. The PUCO authorized us to collect a non-bypassable Service Stability Rider (the “SSR”) equal to $110 million per year for 2014 – 2016. We have the opportunity to seek an additional $45.8 million through extension of the SSR through May 31, 2017, provided we meet certain regulatory filing obligations, which include but are not limited to filing a plan by December 31, 2013 to separate the generation assets from the utility (as noted below, we filed this on December 30, 2013 and a supplemental application on February 25, 2014) and filing a distribution rate case no later than July 1, 2014. The ESP Order also directs us to divest our generation assets no later than May 31, 2017 and sets our SEET threshold at a 12% ROE. Beginning in 2014, we will no longer be permitted to supply 100% of the generation service to our SSO customers. Instead, the PUCO directed us to phase-in the competitive bidding structure with 10% of our SSO load sourced through the competitive bid starting in 2014, 40% in 2015, 70% in 2016 and 100% beginning June 1, 2017. The ESP Order approved our rate proposal to bifurcate our transmission charges into a non-bypassable component, TCRR-N, and a bypassable component, TCRR-B. The ESP Order also required us to establish a $2.0 million per year shareholder funded economic development fund.

Applications for rehearing were filed on October 4, 2013 by us and other parties and are currently pending PUCO action. On October 23, 2013, the PUCO issued an entry on rehearing denying applications for rehearing that related to the competitive bid. The PUCO reaffirmed its position that economic development load should be included in the competitive bid auction and that our affiliates are permitted to bid in the auction. On March 19, 2014, the PUCO issued an entry on rehearing modifying the effective date to complete corporate separation from May 31, 2017 to January 1, 2016 and accelerating the timetable for moving SSO load to an auction process. This order is under review and may be the subject of further PUCO rehearing applications by other parties and us.

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Legal separation of our generating facilities

We filed a generation separation application with the PUCO at the end of December 2013, as required in the ESP Order, and on February 25, 2014, filed a supplemental application. In the supplemental application, we reaffirmed our commitment to separate the generation assets on or before May 31, 2017. We continue to look at multiple options to effectuate the separation including the transfer to an unregulated affiliate or through a sale process. Assuming a transfer to an affiliate, we have requested the ability to, among other things: (a) maintain the greater of, (i) total debt of up to $750 million; or (ii) total debt equal to 75% of ratebase; (b) transfer the assets at a fair market value; and (c) keep OVEC as part of the utility post separation.

COMPETITION AND PJM PRICING

RPM Capacity Auction Price

The PJM RPM capacity base residual auction for the 2016/17 period cleared at a price of $59/MW-day for our RTO area. The per megawatt prices for the periods 2015/16, 2014/15, and 2013/14 were $136/MW-day, $126/MW-day, and $28/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 causes 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 2013, we estimate that a hypothetical increase or decrease of $10 in the capacity auction price would affect our net income by approximately $5.1 million. 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 within “—Market Risk—Commodity Pricing Risk.”

Ohio Competitive Considerations and Proceedings

Since January 2001, our electric customers have been permitted to choose their retail electric generation supplier. We continue to have the exclusive right to provide delivery service in our state certified territory and the obligation to supply retail generation service to customers that do not choose an alternative supplier; however, as discussed above, the supply of electricity for our SSO customers will be sourced through a competitive bid auction. The PUCO maintains jurisdiction over our 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 many of our customers to switch their retail electric services to CRES providers. DPLER, an affiliated company and one of the registered CRES providers, has been marketing generation services to our 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, 2013, 2012 and 2011:

	Year ended December 31, 2013				Year ended December 31, 2012				Year ended December 31, 2011
	Electric Customers		Sales (in millions of kWh)		Electric Customers		Sales (in millions of kWh)		Electric Customers		Sales (in millions of kWh)
Supplied by DPLER		130,303		5,874		73,672		6,201		36,667		5,731
Supplied by non-affiliated CRES providers		87,951		3,471		79,936		1,981		27,812		862
Total supplied in our service territory		218,254		9,345		153,608		8,182		64,479		6,593
Supplied by us in our service territory^(a)		514,926		13,877		513,266		13,999		513,381		14,022

(a)

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

The volumes supplied by DPLER represent approximately 42%, 44% and 41% of our total distribution volumes during the years ended December 31, 2013, 2012 and 2011, 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.

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For the year ended December 31, 2013, approximately 67% of our load was supplied by CRES providers with DPLER supplying 63% of the switched load. Customer switching negatively affected our gross margin during the years ended December 31, 2013, 2012 and 2011 by approximately $318.3 million, $249.0 million and $104.0 million, respectively.

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, 2014 and 2013:

	Three months ended March 31, 2014				Three months ended March 31, 2013
	Electric Customers		Sales (in millions of kWh)		Electric Customers		Sales (in millions of kWh)
Supplied by DPLER^(a)		138,420		1,604		86,801		1,397
Supplied by non-affiliated CRES providers		90,593		999		84,507		822
Total in our service territory		229,013		2,603		171,308		2,219
Distribution sales by our in our service territory		515,748		3,827		514,073		3,586

(a)

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

The volumes supplied by DPLER represent approximately 42% and 39% of our total distribution volumes during the three months ended March 31, 2014 and 2013, respectively. We 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.

Several communities in our 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 move forward with aggregation in our service area, it could have a material effect on our earnings. See “Risk Factors” for more information.

DPLER began providing CRES services to business customers in Ohio who are not in our service territory in 2010 and to residential customers in 2012. Additionally, beginning in March 2011 with the purchase of MC Squared, DPLER services business and residential customers in northern Illinois. The incremental costs and revenues have not had a material effect on our results of operations, financial condition or cash flows.

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 firm wholesale sales requirements for 2014 under contract. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled/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 2014. 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.

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Effective 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. An audit of 2012 fuel costs occurred in 2013. On June 12, 2013, we received a report from the external auditor recommending a pre-tax disallowance of $5.3 million of costs. Hearings in this case were held on December 9-10, 2013 and we expect an order in the case in the second quarter of 2014.

FINANCIAL OVERVIEW

Results of Operations

Years Ended December 31, 2013, 2012 and 2011

Income Statement Highlights

	Years ended December 31,
	2013			2012			2011
$ in millions
Revenues:
Retail	$	782.0		$	898.4		$	1,007.4
Wholesale		671.3			483.7			441.2
RTO revenues		74.5			88.5			76.7
RTO capacity revenues		24.0			63.4			152.4
Mark-to-market gains / (losses)		(0.3	)		(2.2	)		—
Total revenues		1,551.5			1,531.8			1,677.7

Cost of revenues:
Cost of fuel:
Fuel		361.8			351.6			370.2
Losses / (gains) from sale of coal		0.7			11.8			(8.8	)
Gains from sale of emission allowances		—			(0.1	)		—
Mark-to-market (gains) / losses		—			(8.4	)		19.2
Net fuel costs		362.5			354.9			380.6

Purchased power:
Purchased power		236.9			151.6			121.5
RTO charges		109.8			98.8			114.9
RTO capacity charges		33.9			64.1			165.4
Mark-to-market (gains) / losses		1.3			(5.0	)		(0.2	)
Net purchased power		381.9			309.5			401.6

Total cost of revenues		744.4			664.4			782.2

Gross margins^(a)	$	807.1		$	867.4		$	895.5

Gross margins as a % of revenues		52	%		57	%		53	%

Operating income	$	142.4		$	185.0		$	319.9

(a)

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

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Revenues

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

	2013 vs. 2012			2012 vs. 2011
Retail
Rate	$	(7.3	)	$	(20.3	)
Volume		(118.5	)		(85.8	)
Other		9.4			(2.9	)
Total retail change		(116.4	)		(109.0	)

Wholesale
Rate		(64.5	)		(44.8	)
Volume		252.1			87.3
Total wholesale change		187.6			42.5

RTO capacity and other
RTO capacity and other revenues		(53.4	)		(77.2	)

Other
Unrealized MTM		1.9			(2.2	)

Total revenues change	$	19.7		$	(145.9	)

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% 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 we had a number of customers that switched their retail electric service from us to CRES providers, we continued to provide distribution services to those customers within our service territory. Average retail rates decreased slightly overall. The remaining distribution services provided by us 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 our 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 our 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 our 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 our 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.

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During the year ended December 31, 2012, Revenues decreased $145.9 million, or 9%, to $1,531.8 million from $1,677.7 million in the prior year. This decrease was primarily the result of lower average retail rates, retail sales volumes and decreased RTO capacity and other revenues, partially offset by higher wholesale sales volumes and higher average wholesale prices. The revenue components for the year ended December 31, 2012 compared to 2011 are further discussed below:

•

Retail revenues decreased $109.0 million primarily as a result of a 9% decrease in retail sales volumes compared to those in the prior year largely as a result of customer switching due to increased levels of competition to provide transmission and generation services in our service territory. Although we had a number of customers that switched their retail electric service from us to DPLER, an affiliated CRES provider, we continued to provide distribution services to those customers within our service territory, but these services are billed at a lower average rate causing a 2% decrease in retail rates. This decrease in sales volume was partially offset by improved economic conditions and warmer summer weather. The weather conditions resulted in a 9% increase in the number of cooling degree days to 1,264 from 1,160 days in 2011 offset slightly by an 11% decrease in the number of heating degree days to 4,752 days from 5,368 days in 2011. The decrease in average retail rates resulting from customers switching was partially offset by the fuel and energy efficiency riders, increased TCRR and RPM riders and the incremental effect of the recovery of costs under the EIR. The above resulted in an unfavorable $85.8 million retail sales volume variance and an unfavorable $20.3 million retail price variance.

•

Wholesale revenues increased $42.5 million primarily as a result of a 20% increase in wholesale sales volume which was largely a result of the effect of customer switching discussed in the immediately preceding paragraph. We record wholesale revenues from our sale of transmission and generation services to DPLER associated with these switched customers. This increase was partially offset by a 9% decrease in average wholesale rates. This resulted in a favorable $87.3 million wholesale volume variance offset by a $44.8 million unfavorable wholesale price variance.

•

RTO capacity and other revenues, consisting primarily of compensation for use of our transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $77.2 million compared to the same period in 2011. This decrease in RTO capacity and other revenues was primarily the result of an $89.0 million decrease in revenues realized from the PJM capacity auction and a decrease of $1.0 million in transmission and congestion revenues, offset by $12.8 million of revenue recognized as a result of the SECA settlement.

Cost of Revenues

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 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 our 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 our transmission, capacity and other PJM-related charges.

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During the year ended December 31, 2012:

•

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $25.7 million, or 7%, compared to 2011, primarily due to increased mark-to-market gains on coal contracts and decreased fuel costs partially offset by increased losses from the sale of coal. During the year ended December 31, 2012, there was an 11% decrease in the volume of generation at our electric generating stations and mark-to-market gains were $8.4 million compared to $19.2 million of mark-to-market losses for the same period during 2011. Offsetting these decreases were $11.8 million in realized losses from the sale of coal, compared to $8.8 million of realized gains during the same period in 2011.

•

Net purchased power decreased $92.1 million, or 23%, compared to the same period in 2011 due largely to decreased RTO capacity and other charges of $117.4 million which were incurred as a member of PJM, including costs associated with our 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 our transmission, capacity and other PJM-related charges. Partially offsetting these decreases were increased purchased power costs of $30.1 million, $83.5 million due to increased volume offset by $53.3 million due to lower average market prices for purchased power. Purchased power volume increased due to lower internal generation and increased power sales to DPLER and MC Squared. 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.

Operation and Maintenance

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

(a)

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:

•

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.

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	2012 vs. 2011
$ in millions
Low-income payment program^(a)	$	21.3
Energy efficiency programs^(a)		9.2
Generating facilities operating and maintenance expenses		6.0
Pension		5.7
Legal and other consulting costs		3.1
Merger-related costs		(19.4	)
Maintenance of overhead transmission and distribution lines		(10.2	)
Other, net		5.4
Total operation and maintenance expense	$	21.1

(a)

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

During the year ended December 31, 2012, Operation and maintenance expense increased $21.1 million, or 6%, compared to 2011. This variance was primarily the result of:

•

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

•

increased expenses relating to energy efficiency programs that were put in place for our customers;

•

increased expenses for generating facilities largely due to the length and timing of planned outages at jointly-owned production units relative to the same period in 2011;

•

higher pension expenses primarily related to changes in plan assumptions, specifically a lower discount rate and lower expected rate of return on plan assets; and

•

increased expenses related to legal and other consulting services that were not related to the Merger.

These increases were partially offset by:

•

higher costs in the prior year related to the Merger; and

•

decreased expense related to the maintenance of overhead transmission and distribution lines primarily as a result of storms, including a significant ice storm in February 2011.

Depreciation and Amortization

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.

During the year ended December 31, 2012, Depreciation and amortization expense increased $6.4 million, or 5%, compared to 2011. The increase primarily reflects the effect of investments in plant and equipment, partially offset by 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.

General Taxes

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.

During the year ended December 31, 2012, General taxes decreased $1.5 million, or 2%, compared to 2011. This decrease was primarily the result of lower payroll and Ohio commercial activity taxes in 2012 compared to 2011.

Fixed-asset Impairment

During the year ended December 31, 2013, we recorded an impairment of certain generation facilities of $86.0 million. See Note 15 of Notes to our Financial Statements.

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During the year ended December 31, 2012, we recorded an impairment of certain generation facilities of $80.8 million. See Note 15 of Notes to our Financial Statements.

Interest Expense

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 our senior secured bonds.

Interest expense recorded during 2012 did not fluctuate significantly from that recorded in 2011.

Income Tax Expense

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 tax benefits in 2013 and a 2012 adjustment to state deferred taxes.

During the year ended December 31, 2012, Income tax expense decreased $49.1 million compared to 2011 primarily due to decreases in pre-tax income, lower non-deductible compensation expenses related to the Merger and a write-off in 2011 of a deferred tax asset on the termination of the ESOP. These were partially offset by a reduction in Internal Revenue Code Section 199 tax benefits and an adjustment of property-related deferred taxes.

Three Months Ended March 31, 2014 and 2013

Income Statement Highlights

	Three months ended March 31,
	2014			2013
$ in millions
Revenues:
Retail	$	225.4		$	212.6
Wholesale		175.7			140.1
RTO revenues		24.0			18.8
RTO capacity revenues		7.0			4.6
Other mark-to-market gains / (losses)		—			0.4
Total revenues		432.1			376.5

Cost of revenues:
Fuel costs		84.4			86.3
Losses / (gains) from the sale of coal		(0.2	)		1.8
Mark-to-market losses / (gains)		0.1			—
Total fuel		84.3			88.1

Purchased power		104.5			53.3
RTO charges		48.0			25.5
RTO capacity charges		9.8			6.0
Mark-to-market losses		5.7			9.3
Total purchased power		168.0			94.1

Total cost of revenues		252.3			182.2

Gross margin^(a)	$	179.8		$	194.3

Gross margin as a percentage of revenues		42	%		52	%

Operating Income	$	21.5		$	49.6

(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.

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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. Since we plan to utilize our internal generating capacity to supply our 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.

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 throughout the year include: wholesale market prices, our 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. Our plan is to make wholesale sales when market prices allow for the economic operation of our generation facilities that are not being utilized to meet our retail demand.

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

	Three months ended March 31, 2014 vs. 2013
$ in millions
Retail:
Rate	$	5.5
Volume		4.8
Other miscellaneous		2.5
Total retail change		12.8

Wholesale:
Rate		(8.4	)
Volume		44.0
Total wholesale change		35.6

RTO capacity & other:
RTO capacity and other revenues		7.6

Other:
Unrealized MTM		(0.4	)
Total other revenue		(0.4	)

Total revenues change	$	55.6

For the three months ended March 31, 2014, Revenues increased $55.6 million to $432.1 million from $376.5 million in the same period in the prior year. This increase was primarily due to higher wholesale sales volume and increased RTO other revenues with a modest support from increase in retail sales volumes. The volume increases were primarily due to a 15% increase in heating degree days during the period. The changes in the components of revenue are further discussed below:

•

Retail revenues increased $12.8 million due to a $4.8 million increase in retail sales volume and a $5.5 million average retail rate variance. During the three months ended March 31, 2014, heating degree days were up 15% to 3,357 days from 2,928 days for the same period in the prior year. Although we had a number of customers that switched their retail electric service from us to DPLER, an affiliated CRES provider, we continued to provide distribution services to those customers within its service territory. Due to rate changes, average retail rates increased.

•

Wholesale revenues increased $35.6 million as a result of a 31% increase in wholesale sales volume which was largely the result of customer switching discussed in the immediately preceding paragraph. We record wholesale revenues from our sale of transmission and generation services to DPLER associated with these

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switched customers. Also contributing to the increase in wholesale revenues was an 8% increase in generation available from our co-owned and operated generation plants. These resulted in a favorable $44.0 million wholesale volume variance offset by an $8.4 million unfavorable wholesale price variance.

•

RTO capacity and other revenues, consisting primarily of compensation for use of our transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $7.6 million compared to the same period in 2013. This increase was the result of a $5.2 million increase in regulation and operations reserves and transmission losses credits and a $2.4 million increase in revenues realized from the PJM capacity auction.

Cost of Revenues

For the three months ended March 31, 2014:

•

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $3.8 million, or 4%, compared to the same period in 2013, primarily due to decreased fuel costs and increased MTM gains on coal contracts, partially offset by increased losses from MTM fuel.

•

Net purchased power increased $73.9 million, or 79%, compared to the same period in 2013 due largely to increased purchased power costs of $51.2 million: $27.7 million due to increased retail demand and an increase of $23.3 million related to higher average market prices for purchased power, due to the timing of the market purchases. Purchased power volume increased to supply off-system sales. Increases were also due to RTO capacity and other charges of $26.3 million which we incurred as a member of PJM, including costs associated with our load obligations for retail customers. RTO capacity prices are set by an annual auction. Partially offsetting these increases was a decrease in MTM losses of $3.6 million.

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, 2014 vs. 2013
$ in millions
Maintenance of overhead transmission and distribution lines	$	4.7
Energy efficiency programs		2.1
Generating facilities operations and maintenance expense		1.9
Low-income payment program^(a)		(2.2	)
Other, net		(2.4	)
Total change in operation and maintenance expense	$	4.1

(a)

There is a corresponding decrease in Revenues associated with this program resulting in no impact to Net Income.

For the three months ended March 31, 2014, Operation and maintenance expense increased $4.1 million, or 5%, compared to the same period in the prior year. This variance was primarily the result of:

•

increased expenses related to the maintenance of overhead transmission and distribution lines and a settlement related to an agreement in principle with the PUCO Staff on storm costs to be recovered,

•

increased expenses relating to energy efficiency programs that were put in place for our customers, and

•

increased expenses for generating facilities largely due to high production volume to meet customer demand during the cold weather months relative to the same period in 2013.

These increases were partially offset by:

•

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

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Depreciation and Amortization

For the three months ended March 31, 2014, Depreciation and amortization expense increased $2.9 million compared to the same period in the prior year as a result of routine plant additions and replacements partially offset by a reduction in the depreciation expense for the East Bend and Conesville plants as a consequence of the December 2013 impairment write-downs of those two plants.

General Taxes

For the three months ended March 31, 2014, General taxes increased $6.6 million, compared to the same period in the prior year. The increase was primarily due to an adjustment to the 2013 estimated liability to true up to actual payments to be made in 2014 and higher property tax accruals for 2014 compared to 2013.

Interest Expense

Interest expense recorded during the three months ended March 31, 2014 decreased $1.5 million compared to the same period in the prior year due to the refinancing of bonds at a lower interest rate.

Income Tax Expense

For the three months ended March 31, 2014, Income tax expense decreased $5.6 million compared to the same period in 2013, primarily due to lower pre-tax income in 2014.

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FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS

The following tables provide a summary of our cash flows:

	Years ended December 31,
	2013			2012			2011
$ in millions
Net cash from operating activities	$	335.3		$	339.8		$	364.2
Net cash from investing activities		(114.5	)		(197.5	)		(185.0	)
Net cash from financing activities		(226.4	)		(146.0	)		(201.0	)

Net change		(5.6	)		(3.7	)		(21.8	)
Cash and cash equivalents at beginning of period		28.5			32.2			54.0
Cash and cash equivalents at end of period	$	22.9		$	28.5		$	32.2

	Three months ended March 31,
	2014			2013
$ in millions
Net cash provided by operating activities	$	10.2		$	101.8
Net cash used for investing activities		(44.7	)		(46.8	)
Net cash from financing activities		14.8			(55.2	)
Net change		(19.7	)		(0.2	)
Cash and cash equivalents at beginning of period		22.9			28.5
Cash and cash equivalents at end of period	$	3.2		$	28.3

Net Cash provided by Operating Activities

Net cash provided by operating activities for the years ended December 31, 2013, 2012 and 2011 are summarized as follows:

	Years ended December 31,
	2013			2012			2011
$ in millions
Net income	$	83.6		$	91.2		$	193.2
Depreciation and amortization		140.2			141.3			134.9
Deferred income taxes		(16.8	)		3.6			50.7
Fixed asset impairment		86.0			80.8			—
Recognition of deferred SECA		—			(17.8	)		—
Contribution to pension plan		—			—			(40.0	)
Deferred regulatory assets, net		7.8			(1.5	)		(12.6	)
Other		34.5			42.2			38.0
Net cash from operating activities	$	335.3		$	339.8		$	364.2

Net cash provided by operating activities for the three months ended March 31, 2014 and 2013 are summarized as follows:

	Three months ended March 31,
	2014		2013
$ in millions
Net income	$	9.4	$	30.2
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		36.5		33.6
Deferred income taxes		1.4		22.9

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	Three months ended March 31,
	2014			2013
Changes in certain assets and liabilities:
Accounts receivable	$	(14.8	)	$	13.2
Inventories		(10.3	)		(4.3	)
Prepaid taxes		0.3			—
Taxes applicable to subsequent years		13.5			16.7
Deferred regulatory costs, net		(5.7	)		3.6
Accounts payable		34.0			2.7
Accrued taxes payable		(21.5	)		(25.3	)
Accrued interest payable		(5.8	)		2.3
Pension, retiree and other benefits		0.8			3.2
Unamortized investment tax credit		(0.6	)		(0.6	)
Other		(27.0	)		3.6
Net cash from operating activities	$	10.2		$	101.8

Net Cash used for Investing Activities

Net cash used for investing activities for the years ended December 31, 2013, 2012 and 2011 are summarized as follows:

	Years ended December 31,
	2013			2012			2011
$ in millions
Environmental and renewable energy capital expenditures	$	(2.4	)	$	(8.2	)	$	(11.8	)
Other plant-related asset acquisitions		(119.7	)		(187.3	)		(192.7	)
Insurance proceeds		14.2			—			—
Proceeds from liquidation of DPL stock, held in trust		—			—			26.9
Other		(6.6	)		(2.0	)		(7.4	)
Net cash from investing activities	$	(114.5	)	$	(197.5	)	$	(185.0	)

During the year ended December 31, 2013, our environmental expenditures were primarily related to pollution control devices at our generation stations. In addition, we received $14.2 million in insurance proceeds during the year, $6.6 million of which were from DPL’s MVIC subsidiary.

During the year ended December 31, 2012, our environmental expenditures were primarily related to pollution control devices at our generation stations.

During the year ended December 31, 2011, our environmental expenditures were primarily related to pollution control devices at our generation stations. Additionally, we received proceeds of $26.9 million related to the liquidation of DPL stock held in the Master Trust.

Net cash used for investing activities for the three months ended March 31, 2014 and 2013 are summarized as follows:

	Three months ended March 31,
	2014			2013
$ in millions
Capital expenditures	$	(27.4	)	$	(33.6	)
Purchase of emission allowances		(0.1	)		—
Purchase of renewable energy credits		(1.2	)		(0.5	)
Increase in restricted cash		(16.0	)		(12.7	)
Net cash used for investing activities	$	(44.7	)	$	(46.8	)

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During the three months ended March 31, 2014 and 2013, the significant components of our Net cash used for investing activities were primarily for assets acquired at our generation plants.

Net Cash used for Financing Activities

Net cash used for financing activities for the years ended December 31, 2013, 2012 and 2011 are summarized as follows:

	Years ended December 31,
	2013			2012			2011
$ in millions
Dividends paid on common stock	$	(190.0	)	$	(145.0	)	$	(220.0	)
Retirement of long-term debt		(470.0	)		—			—
Issuance of long-term debt		445.0			—			—
Cash contribution from parent		—			—			20.0
Other		(11.4	)		(1.0	)		(1.0	)
Net cash from financing activities	$	(226.4	)	$	(146.0	)	$	(201.0	)

During the year ended December 31, 2013, net cash used for financing activities primarily relates to $190 million in dividends and the issuance of new senior secured bonds, the proceeds of which were used to redeem bonds at maturity.

During the year ended December 31, 2012, net cash used for financing activities primarily relates to $145 million in dividends.

During the year ended December 31, 2011, net cash used for financing activities primarily relates to $220 million in dividends offset by $20 million of additional capital contributed by DPL.

Net cash used for investing activities for the three months ended March 31, 2014 and 2013 are summarized as follows:

	Three months ended March 31,
	2014			2013
$ in millions
Dividends paid on common stock to parent	$	—		$	(55.0	)
Issuance of notes payable - related party		15.0			—
Dividends paid on preferred stock		(0.2	)		(0.2	)
Net cash from financing activities	$	14.8		$	(55.2	)

During the three months ended March 31, 2014, our Net cash provided by financing activities related to the issuance of short term debt between DPL and DP&L.

During the three months ended March 31, 2013, our Net cash used for financing activities relates to dividends paid.

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 2014 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from the 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.

At the date of this prospectus, we have access to a revolving credit facility, which was established in May 2013 and will expire in May 2018. This revolving credit facility has nine participating banks, with no bank having more than 22.5% of the total commitment of $300.0 million. This revolving credit facility has a $100.0 million letter of

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credit sublimit and we also have the option to increase the potential borrowing amount under this facility by $100.0 million. We had no outstanding borrowings under this facility at March 31, 2014. At March 31, 2014, there was a letter of credit in the amount of $0.4 million outstanding, with the remaining $299.6 million available to us.

Cash and cash equivalents for us amounted to $3.2 million at March 31, 2014. At that date, we had no short-term investments that were not included in cash and cash equivalents.

Capital Requirements

CONSTRUCTION

Actual			Projected
2011	2012	2013	2014	2015	2016
$199	$177	$111	$125	$116	$126

Planned construction additions for 2014 relate primarily to new investments in and upgrades to our 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.

We are projecting to spend an estimated $367.0 million in capital projects for the period 2014 through 2016. Approximately $5.0 million of this projected amount is to enable us to meet the recently revised reliability standards of NERC. We are subject to the mandatory reliability standards of NERC and Reliability First Corporation (the “RFC”), one of the eight NERC regions, of which we are a member. NERC has recently changed the definition of the Bulk Electric System to include 100 kV and above facilities, thus expanding the facilities to which the reliability standards apply. Our 138 kV facilities were previously not subject to these reliability standards. Accordingly, we anticipate spending approximately $65.0 million within the next five years to reinforce our 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.

Debt Covenants

In May 2013, we terminated our two $200.0 million revolving credit facilities and replaced them with a new $300.0 million revolving credit facility. Each of the facilities that were terminated in May had a Total Debt to Total Capitalization financial covenant. Our new revolving credit facility that was put in place in May 2013 also has a financial covenant that requires the Total Debt to Total Capitalization ratio to not exceed 0.65 to 1.00. As of March 31, 2014, this covenant was met with a ratio of 0.44 to 1.00. The above ratio is calculated as the sum of our current and long-term portion of debt, including our guarantee obligations, divided by the total of our shareholder’s equity and total debt including guarantee obligations. In addition, the new revolving credit facility that was put in place in May 2013 has a second financial covenant that did not exist in the previous agreements. The second covenant is an EBITDA to Interest Expense ratio that will be 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. Our EBITDA to Interest Expense ratio cannot be less than 2.50 to 1.00. As of March 31, 2014, this covenant was met with a ratio of 8.74 to 1.00.

Debt Ratings

On September 10, 2013, Moody’s and Fitch downgraded our credit and debt ratings and updated our outlooks to Stable.

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

	DP&L^(a)	Outlook	Effective
Fitch Ratings	BBB	Stable	September 2013
Moody's Investors Service, Inc.	Baa1	Stable	September 2013
Standard & Poor's Financial Services LLC	BBB-	Stable	May 2014

(a)

Rating relates to our Senior Secured debt.

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Credit Ratings

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

	DP&L	Outlook	Effective
Fitch Ratings	BB+	Stable	September 2013
Moody's Investors Service, Inc.	Baa3	Stable	September 2013
Standard & Poor's Financial Services LLC	BB	Stable	May 2014

Standard and Poor’s Ratings Services did not change our Credit Rating or Debt Rating in 2013.

On September 10, 2013 Fitch downgraded our issuer default rating to BB+ (from BBB-) and downgraded our senior secured rating to BBB (from BBB+). The outlooks of our ratings were changed to a Stable outlook.

On November 9, 2012, Moody’s Investors Services, Inc. placed our ratings under review for possible downgrade. On September 9, 2013, Moody’s downgraded our issuer default rating to Baa3 (from Baa2) and downgraded our senior secured rating to Baa1 (from A3). The outlooks of our ratings were changed to a Stable outlook.

The above mentioned changes in ratings from our rating agencies could have an impact on the market price of our debt and our preferred stock.

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.

Off-Balance Sheet Arrangements

Guarantees

We own 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, 2014, we could be responsible for the repayment of 4.9%, or $76.0 million, of a $1,550.2 million debt obligation that features maturities ranging from 2018 to 2040. This would only happen if this electric generation company defaulted on its debt payments. As of March 31, 2014, we have no knowledge of such a default.

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, 2013, 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	$	877.8	$	0.2	$	445.2	$	0.2	$	432.2
Interest payments		361.0		24.1		48.4		31.7		256.8
Pension and postretirement payments		264.5		27.2		51.9		52.3		133.1
Operating leases		0.6		0.4		0.2		—		—
Coal contracts^(a)		625.6		216.5		270.3		138.8		—
Limestone contracts^(a)		24.4		6.1		12.2		6.1		—
Purchase orders and other contractual obligations		85.6		48.8		18.7		18.1		—
Total contractual obligations	$	2,239.5	$	323.3	$	846.9	$	247.2	$	822.1

(a)

Total at units operated by us.

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Long-term debt

Our long-term debt as of March 31, 2014 consisted of our first mortgage bonds, tax-exempt pollution control bonds, capital leases and the WPAFB note. These long-term debt amounts include current maturities but exclude unamortized debt discounts.

See Note 6 of the Notes to our 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, 2013.

Purchase orders and other contractual obligations

As of December 31, 2013, we 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 $8.8 million at December 31, 2013, 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.

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 above since December 31, 2013.

MARKET RISK

We are subject to certain market risks including, but not limited to, changes in commodity prices for electricity, coal, environmental emission allowances, 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 (the “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 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 operated generation units, we use a variety of non-derivative and derivative instruments including forward contracts and futures contracts. These instruments are used principally for economic hedging purposes and none are held for trading purposes. Derivatives that fall within the scope of derivative accounting under GAAP must be recorded at their fair value and marked to market unless they qualify for cash flow hedge accounting. MTM gains and losses on derivative instruments that qualify for cash flow hedge accounting are deferred in AOCI until the forecasted transactions occur. We adjust the derivative instruments that do not qualify for cash flow hedging to fair value on a monthly basis 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 firm wholesale sales requirements for 2014 under contract, sales requirements may change. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled outages and generation plant mix. 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, the Dodd-Frank Act, signed into law in July 2010, 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.

A 10% increase or decrease in the market price of our heating oil forwards at December 31, 2013 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, 2013 and the effect to Net income if the market price were to increase or decrease by 10%:

Power Forwards	Contract Volume (in millions of tons)			Weighted Average Market Price per ton		Increase / decrease in Net income (in millions)
2014- Net Purchase/(Sale) Position		0.8		$	36.44	$	1.9
2015- Net Purchase/(Sale) Position		(0.2	)	$	39.83	$	(0.5	)
2016- Net Purchase/(Sale) Position		(0.3	)	$	38.07	$	(0.7	)

At March 31, 2014, a 10% increase or decrease in the market price of our heating oil forwards would not have a significant effect on Net income. 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 $7.2 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 $10.2 million.

Wholesale revenues

Approximately 45% of our electric revenues for the year ended December 31, 2013 were from sales of excess energy and capacity in the wholesale market (our electric revenues in the wholesale market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.

Approximately 36% of our electric revenues for the year ended December 31, 2012 were from sales of excess energy and capacity in the wholesale market (our electric revenues in the wholesale market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.

Approximately 35% of our electric revenues for the year ended December 31, 2011 were from sales of excess energy and capacity in the wholesale market. Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.

The table below provides the effect on annual net income (net of an estimated income tax at 35%) as of December 31, 2013 of a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power

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(our 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):

$ in millions
Effect of 10% change in price per MWh	$	14.1

Approximately 42% of our electric revenues for the three months ended March 31, 2014 were from sales of excess energy and capacity in the wholesale market (our electric revenues in the wholesale market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.

Approximately 38% of our electric revenues for the three months ended March 31, 2013 were from sales of excess energy and capacity in the wholesale market (our electric revenues in the wholesale market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.

The table below provides the effect on annual net income (net of an estimated income tax at 35%) as of March 31, 2014 of a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power (our 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):

$ in millions
Effect of 10% change in price per MWh	$	10.2

RPM Capacity revenues and costs

As a member of PJM, we receive revenues from the RTO related to our transmission and generation assets and incur costs associated with our load obligations for retail customers. PJM, which has a delivery year which runs from June 1 to May 31, has conducted auctions for capacity through the 2016/17 delivery year. The clearing prices for capacity during the PJM delivery periods from 2012/13 through 2016/17 are as follows:

	PJM Delivery Year
($/MW-day)	2012/13		2013/14		2014/15		2015/16		2016/17
Capacity clearing price	$	16	$	28	$	126	$	136	$	59

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

	Calendar Year
($/MW-day)	2012		2013		2014		2015		2016
Computed average capacity price	$	55	$	23	$	85	$	132	$	91

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 our capacity revenues and costs. Although we currently have 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.

The table below provides estimates of the effect on annual net income (net of an estimated income tax at 35%) as of December 31, 2013 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, 2013. As of December 31, 2013, approximately 28% of our RPM capacity revenues and costs were recoverable from SSO retail customers through the RPM rider.

$ in millions
Effect of $10/MW-day change in capacity auction pricing	$	5.0

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The table below provides estimates of the effect on annual net income (net of an estimated income tax at 35%) as of March 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 March 31, 2014. As of March 31, 2014, approximately 32% of our RPM capacity revenues and costs were recoverable from SSO retail customers through the RPM rider.

$ in millions
Effect of $10/MW-day change in capacity auction pricing	$	5.1

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.

Fuel and purchased power costs

Our 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, 2013, 2012 and 2011 were 45%, 39% and 37%, respectively. Our fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the three months ended March 31, 2014 and 2013 were 41% and 42%, repectively. We have a significant portion of projected 2014 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 2014; 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 2014 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 generation plant mix.

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

Effective January 1, 2010, we were allowed to recover our SSO retail customer’s share of fuel and purchased power costs as part of the fuel rider approved by the PUCO. Since there has been an increase in customer switching, as of March 31, 2014, SSO customers represented approximately 35% of our total fuel costs. The table below provides the effect on annual Net income (net of an estimated income tax at 35%) as of December 31, 2013, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate 28% recovery:

$ in millions
Effect of 10% change in fuel and purchased power	$	28.0

The following table provides the effect on annual Net income (net of an estimated income tax at 35%) as of March 31, 2014, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate 32% recovery:

$ in millions
Effect of 10% change in fuel and purchased power	$	28.7

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. We have both fixed-rate and variable rate long-term debt. Our variable-rate debt is comprised 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.

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We partially hedged against interest rate fluctuations in the Old Bonds 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 in the Old Bonds and the effect this could have on our future borrowing costs. On September 16, 2013 and immediately after the sale of our new $445 million of first mortgage bonds, we settled all of the above mentioned swap agreements at a total net settlement of $0. As of December 31, 2013, we do not have any interest rate hedging agreements still in place.

The carrying value of our debt was $877.8 million at March 31, 2014, consisting of our first mortgage bonds, tax-exempt pollution control bonds, capital leases and the WPAFB note. The fair value of this debt at March 31, 2014 was $878.6 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 our debt obligations that are sensitive to interest rate changes. Note that our debt was not revalued as a result of the Merger.

Principal Payments and Interest Rate Detail by Contractual Maturity Date

	Twelve Months Ending March 31,																		Principal amount at March 31, 2014		Fair value at March 31, 2014
	2015			2016			2017			2018			2019			Thereafter			Principal amount at March 31, 2014		Fair value at March 31, 2014
$ in millions
Long-term debt
Variable-rate debt	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0	$	100.0
Average interest rate		0.0	%		0.0	%		0.0	%		0.0	%		0.0	%		0.1	%
Fixed-rate debt	$	0.2		$	0.1		$	445.1		$	0.1		$	0.1		$	332.2			777.8		778.6
Average interest rate		4.8	%		4.2	%		1.9	%		4.2	%		4.2	%		4.8	%
Total																			$	877.8	$	878.6

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 December 31, 2013 and March 31, 2014 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 December 31, 2013 and March 31, 2014, 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

	Carrying value at December 31, 2013^(a)		Fair value at December 31, 2013		One Percent Interest Rate Risk		Carrying value at March 31, 2014^(a)		Fair value at March 31, 2014		One Percent Interest Rate Risk
$ in millions
Long-term debt
Variable-rate debt	$	100.0	$	100.0	$	1.0	$	100.0	$	100.0	$	1.0
Fixed-rate debt		777.1		759.6		7.6		777.1		778.6		7.8
Total	$	877.1	$	859.6	$	8.6	$	877.1	$	878.6	$	8.8

(a)

Carrying value includes unamortized debt discounts and premiums.

Our interest rate risk with respect to our long-term debt primarily relates to the potential impact a decrease in interest rates of one percentage point has on the fair value of our $778.6 million of fixed-rate debt and not on our financial condition or our results of operations. On the variable-rate debt, the interest rate risk with respect to our long-term debt represents the potential impact an increase of one percentage point in the interest rate has on our results of operations related to the fair value of our $100.0 million variable-rate long-term debt outstanding as of March 31, 2014.

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Equity Price Risk

As of March 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 $65.7 million at March 31, 2014. We believe a hypothetical 10% decrease in prices quoted by stock exchanges during 2014 would not have any material effect on the 2014 pension expense. The 2014 pension expense will not change unless an unusual event would occur during 2014 which would require an actuarial re-measurement.

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.

Critical Accounting Estimates

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

Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Historically, however, recorded estimates have not differed materially from actual results. Significant items subject to such judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.

Impairments and Assets Held for Sale

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 our Financial Statements discussing the impairment of our long-lived assets in 2013 and 2012.

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 the end of each month, unbilled revenues

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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 our 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 4 of Notes to our 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.

Insurance and Claims Costs

We are responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. In addition, we have estimated liabilities for medical, life and disability claims costs below certain coverage thresholds of third-party providers. We record these additional insurance and claims costs of approximately

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$18.8 million and $17.7 million for 2013 and 2012, respectively, within Other current liabilities and Other deferred credits on our balance sheet. The estimated liabilities for workers’ compensation, medical, life and disability claims 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 2014, we are decreasing our long-term rate of return assumption from 7.00% to 6.75% for pension plan assets and we are maintaining 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 2014, we have increased our assumed discount rate to 4.86% from 4.04% for pension and to 4.58% from 3.75% 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 2014 pension expense of approximately $3.4 million. A 25 basis point increase in the discount rate for pension would result in a decrease of approximately $0.3 million to 2014 pension expense. A 25 basis point decrease in the discount rate for pension would result in an increase of approximately $0.3 million to 2014 pension expense. A one percent change in the rate of return assumption for pension would result in an increase or decrease to the 2014 pension expense of approximately $3.5 million. A one percent increase in the discount rate for pension would result in a decrease of approximately $1.5 million to 2014 pension expense. A one percent decrease in the discount rate for pension would result in an increase of approximately $2.8 million to 2014 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

Organization

We are 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. We have the exclusive right to provide such service to our more than 515,000 customers located in West Central Ohio. Additionally, we offer retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generate electricity at seven coal-fired power stations. Beginning in 2014, we are required to source 10% of the generation of our standard service offer customers through a competitive bid process. Principal industries located in our service territory include automotive, food processing, paper, plastic, manufacturing and defense. Our sales reflect the general economic conditions, seasonal weather patterns of the area and the market price of electricity. We sell any excess energy and capacity into the wholesale market. We also sell electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER’s retail customers.

We do not have any subsidiaries. All of our outstanding shares of common stock are held by DPL, which became our corporate parent, effective April 21, 1986. Our ultimate parent is AES.

Our electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while our generation business is deemed competitive under Ohio law. Accordingly, we apply the accounting standards for regulated operations to our 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.

As of March 31, 2014, DP&L employed approximately 1,189 people. Approximately 63% of all DP&L employees are under a collective bargaining agreement which expires on October 31, 2014.

ELECTRIC OPERATIONS AND FUEL SUPPLY

2013 Summer Generating Capacity
(in MW)

Coal fired	Combustion Turbines, Diesel Units and Solar	Total
2,465	432	2,897

Our present summer generating capacity, including peaking units, is 2,897 MW. Of this capacity, 2,465 MW, or 85%, is derived from coal-fired steam generating stations and the balance of 432 MW, or 15%, 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 our 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. The coal-fired portion of our 100% owned steam generating station (Hutchings) was deactivated in September 2013. Additionally, we, Duke Energy and AEP Generation own, as tenants in common, 880 circuit miles of 345,000-volt transmission lines. We have several interconnections with other companies for the purchase, sale and interchange of electricity.

In 2013, we generated 99% of our electric output from coal-fired units and 1% from solar, oil and natural gas-fired units.

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The following table sets forth our generating stations and, where indicated, those stations which we own as tenants in common:

				Approximate Summer MW Rating
Station	Ownership^(a)	Operating Company	Location	DP&L Portion^(b)		Total
Coal Units
Killen	C	DP&L	Wrightsville, OH		402		600
Stuart	C	DP&L	Aberdeen, OH		808		2,308
Conesville-Unit 4	C	AEP Generation	Conesville, OH		129		780
Beckjord-Unit 6	C	Duke Energy	New Richmond, OH		207		414
Miami Fort-Units 7 & 8	C	Duke Energy	North Bend, OH		368		1,020
East Bend-Unit 2	C	Duke Energy	Rabbit Hash, KY		186		600
Zimmer	C	Duke Energy	Moscow, OH		365		1,300

Solar, Combustion Turbines or Diesel
Hutchings	W	DP&L	Miamisburg, OH		25		25
Yankee Street	W	DP&L	Centerville, OH		101		101
Yankee Solar	W	DP&L	Centerville, OH		1		1
Monument	W	DP&L	Dayton, OH		12		12
Tait Diesels	W	DP&L	Dayton, OH		10		10
Sidney	W	DP&L	Sidney, OH		12		12
Tait Units 1 - 3	W	DP&L	Moraine, OH		256		256
Killen	C	DP&L	Wrightsville, OH		12		18
Stuart	C	DP&L	Aberdeen, OH		3		10
Total approximate summer generating capacity					2,897		7,467

(a)

W = Wholly-owned C = Commonly-owned

(b)

DP&L portion of commonly-owned generating stations

As part of a settlement with the USEPA, we signed a Consent Agreement and Final Order (the “CAFO”) that was filed on September 26, 2013 and an Administrative Consent Order. Together, these two agreements resolved the opacity and particulate emissions NOV at the Hutchings Station and required that all six coal-fired units at Hutchings cease operating on coal by September 30, 2013, and included an immaterial penalty and the completion of a Supplemental Environmental Project of $0.2 million within one year. The units were disabled for coal operations prior to September 30, 2013. The removal of this capacity has been reflected in the table above.

In addition to the above, we also own 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. Our share of this generation capacity is 103 MW.

We have a significant portion of the total expected coal volume needed to meet our retail and wholesale sales requirements for 2014 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 2014.

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

Average cost of Fuel Consumed (cents per kWh)
2013	2012	2011
2.40	2.72	2.71

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

Our sales to SSO retail customers are subject to rate regulation by the PUCO. In addition, certain of our recoverable costs are considered to be non-bypassable and are therefore assessed to all our retail customers, under the regulatory authority of the PUCO, regardless of whom the customer selects to supply its retail electric service. Our 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 our balance sheet. See Note 4 of Notes to our Financial Statements.

COMPETITION AND REGULATION

Ohio Matters

Ohio Retail Rates

The PUCO maintains jurisdiction over our delivery of electricity, SSO and other retail electric services.

On May 1, 2008, substitute SB 221, an Ohio electric energy bill, was signed by the Governor and went into effect July 31, 2008. This law required that all Ohio distribution utilities file either an ESP or MRO to establish rates for SSO service. 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 cost-based 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 option involve a SEET based on the earnings of comparable companies with similar business and financial risks.

On October 5, 2012, we filed an ESP with the PUCO to establish SSO rates that were to be in effect starting January 2013. The plan was refiled on December 12, 2012 to correct for certain projected costs. The 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 our service territory that have not chosen an alternative generation supplier. The ESP Order was issued by the PUCO on September 4, 2013 and a correction to the ESP Order was issued on September 6, 2013.

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The ESP Order stated that our next ESP began January 2014 and extends through May 31, 2017. The PUCO authorized us to collect a non-bypassable SSR equal to $110 million per year for 2014 – 2016. We have the opportunity to seek an additional $45.8 million through extension of the SSR through May 31, 2017, provided we meet certain regulatory filing obligations, which include but are not limited to filing a plan by December 31, 2013 to separate the generation assets from the utility (as noted below, we filed this on December 30, 2013) and filing a distribution rate case no later than July 1, 2014. The ESP Order also directs us to divest our generation assets no later than May 31, 2017 and sets our SEET threshold at a 12% ROE. Beginning in 2014, we are no longer permitted to supply 100% of the generation service for SSO customers. Instead, the PUCO directed us to phase-in the competitive bidding structure with 10% of our SSO load sourced through the competitive bid starting in 2014, 40% in 2015, 70% in 2016, and 100% by June 1, 2017. The ESP Order approved our rate proposal to bifurcate our transmission charges into a non-bypassable component, TCRR-N, and a bypassable component, TCRR-B. The ESP Order also required us to establish a $2.0 million per year shareholder funded economic development fund. Applications for rehearing were filed on October 4, 2013 by us and other parties and are currently pending PUCO action. On October 23, 2013, the PUCO issued an entry on rehearing denying applications for rehearing that related to the competitive bid. The PUCO reaffirmed its position that economic development load should be included in the competitive bid auction and that our affiliates are permitted to bid in the auction.

In accordance with the ESP Order, on December 30, 2013, we filed an application with the PUCO stating our plan to separate our generation assets to an affiliated entity on or before May 31, 2017. Comments and reply comments were filed. We amended our application on February 25, 2014. Additional comments and reply comments have been filed and the case is awaiting an order from the PUCO.

SB 221 and the implementation rules contain targets relating to advanced energy portfolio standards, 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 we met our renewable targets for compliance years 2008 – 2012. Filing for compliance year 2013 was made on April 15, 2014, and we are reported to be in full compliance with all renewable targets. We plan to file our next energy efficiency portfolio plan in 2015. However, as the energy efficiency and alternative energy targets get increasingly larger over time, the costs of complying with SB 221 and the PUCO’s implementing rules could have a material effect on our financial condition or results of operations.

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 report from that external auditor recommending a pre-tax disallowance of $5.3 million of costs. Hearings in this case were held on December 9-10, 2013, and we expect an order in the case in the second quarter of 2014.

As a member of PJM, we receive revenues from the RTO related to our transmission and generation assets and incur costs associated with our load obligations for retail customers. SB 221 includes a provision that would allow Ohio electric utilities to seek and obtain a reconcilable rider to recover RTO-related costs and credits. Our 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 will begin 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 our 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. Our annual true-up of these riders was approved by the PUCO by Order dated April 24, 2013, and our 2014 filings will be made in the first and second quarters of 2014.

For calendar year 2012 we were subject to a SEET threshold in which we were required to apply general rules for calculating the earnings and comparing them to a comparable group to determine whether there were significantly

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excessive earnings. Pursuant to an Order issued on February 13, 2014, our 2012 earnings were found to not be excessive. Through the ESP Order, the PUCO established our ROE SEET threshold at 12% beginning with 2013. In future years, the SEET could have a material effect on our results of operations, financial condition and cash flows.

On June 29, 2012, we filed our application to establish reliability targets consistent with the most recent PUCO Electric Service and Safety Standards (the “ESSS”). We and PUCO Staff reached a settlement establishing new reliability targets in this case. The settlement was approved by the PUCO on October 4, 2013. According to the ESSS rules, all Ohio utilities are subject to financial penalties if the established targets are not met for two consecutive years. As of December 31, 2013, we have not missed any of the reliability targets.

Ohio Competitive Considerations and Proceedings

Since January 2001, our electric customers have been permitted to choose their retail electric generation supplier. We continue to have the exclusive right to provide delivery service in our 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 our 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, 2013, there were thirty-six CRES providers registered in our service territory. DPLER, an affiliated company and one of the thirty-six registered CRES providers, has been marketing supply services to our customers. During 2013, DPLER accounted for approximately 5,874 million kWh of the total 9,345 million kWh supplied by CRES providers within our service territory. Also during 2013, 87,951 customers with an annual energy usage of 3,471 million kWh were supplied by other CRES providers within our service territory. The volume supplied by DPLER represents approximately 42% of our total distribution sales volume during 2013. The reduction to gross margin in 2013 as a result of customers switching to DPLER and other CRES providers was approximately $318.3 million. 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 us, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.

Several communities in our 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 our service area move forward with aggregation, it could have a material effect on our earnings.

Federal Matters

Like other electric utilities and energy marketers, we may sell or purchase electric products on the wholesale market. We compete with other generators, power marketers, privately and municipally-owned electric utilities and rural electric cooperatives when selling electricity. Our ability to sell this electricity will depend not only on the performance of our generating units, but also on how our 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, we successfully integrated our 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 2016/17 period cleared at a price of $59/MW-day for our RTO area. The prices for the periods 2015/16, 2014/15 and 2013/14 were $136/MW-day, $126/MW-day and $28/MW-day, respectively, based on previous auctions. Future RPM auction results will be dependent not only on the

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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 RPM capacity auctions. Increases in customer switching causes 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 if the current auction price is not sustained, 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 (the “CIP”) reliability standards, across eight reliability regions. In December 2012, we underwent routine, scheduled NERC audits conducted by the RFC, which focused on our performance in supporting PJM as our transmission operator, and our compliance with the CIP standards. We were found 100% compliant in our performance in support of PJM. In the CIP audit, four minor documentation-related Possible Alleged Violations (“PAV”) were identified, which were settled through a streamlined process, without any financial penalties. In November 2013, DPLE, DPL’s merchant generation affiliate, underwent a routine, scheduled NERC audit, during which one minor PAV was identified; it is anticipated that it will be settled through a streamlined process, with no financial penalty.

ENVIRONMENTAL MATTERS

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

•

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

•

Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to 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. We have installed emission control technology and are 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 may require 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. The USEPA has previously determined that fly ash and other coal combustion by-products are not hazardous waste subject to the Resource Conservation and Recovery Act (the “RCRA”), but the USEPA is reconsidering that determination and planning to propose a new rule regulating coal combustion by-products. A change in determination or other additional regulation of fly ash or other coal combustion byproducts could significantly increase the costs of disposing of such 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 $1.1 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 of 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.

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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; especially the stations that do not have SCR and FGD equipment installed to further control certain emissions. Currently, the coal-fired generation unit Beckjord Unit 6, in which we have a 50% ownership interest, does not have such emission-control equipment installed. This unit is scheduled to be deactivated on June 1, 2015. DPL valued Beckjord Unit 6 at zero at the Merger date. We are depreciating Unit 6 through December 2014 and do not believe that any additional accruals or impairment charges are needed as a result of this decision.

We deactivated the coal units at Hutchings Station in September 2013 as part of a settlement with the USEPA discussed in more detail below.

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 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 the “Clean Air Interstate Rule” (the “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 is 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 response to the D.C. Circuit's opinion, on July 7, 2011, the USEPA the Cross-State Air Pollution Rule (“CSAPR”). Starting in 2012, CSAPR would have required significant reductions in SO₂ and NO_x emissions from covered sources, such as power stations in 28 eastern states. Once fully implemented in 2014, the rule would have required additional SO₂ emission reductions of 73% and additional NO_x reductions of 54% from 2005 levels. Many states, utilities and other affected parties filed petitions for review, challenging the CSAPR before the U.S. Court of Appeals for the District of Columbia. 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 are to continue to serve as the governing program until the USEPA takes further action or the U.S. Congress intervenes. On October 5, 2012, the USEPA, several states and cities, as well as environmental and health organizations, filed petitions with the D.C. Circuit Court requesting a rehearing by all of the judges of the D.C. Circuit Court of the case pursuant to which the three-judge panel ruled that CSAPR be vacated, which were denied. On June 24, 2013, the U.S. Supreme Court agreed to review the D.C. Circuit Court’s decision to vacate CSAPR. On April 29, 2014, the U.S. Supreme Court upheld CSAPR, remanding the case back to the D.C. Circuit Court for further proceedings. At this time, it is not possible to predict the details of such a replacement transport rule or what impacts it may have on our consolidated financial condition, results of operations or cash flows.

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, but may be granted an additional year to become compliant contingent on Ohio EPA approval. We are evaluating the costs that may be incurred to comply with the new requirement; however, MATS could have a material adverse effect on our results of operations and result in material compliance costs.

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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 our generation facilities. The regulation contains emissions limitations, operating limitations and other requirements. We expect to be in compliance with this rule and the costs are not currently expected to be material to our 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 we operate and/or own generating facilities. On December 31, 2012, the USEPA redesignated Adams County, where Stuart and Killen are located, to attainment status. On December 14, 2012, the USEPA tightened the PM 2.5 standard to 12.0 micrograms per cubic meter. This will begin a process of redesignations during 2014, including in counties where we have generating stations. We cannot predict the effect the revisions to the PM 2.5 standard will have on our 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. We cannot determine the effect of revisions to the ozone standard, if any, on our operations; however, none of our operations are located in non-attainment areas. The USEPA is required to review the ozone standard and is expected to propose a more stringent standard in 2014 or 2015. In addition, in December 2013, eight northeastern states petitioned the USEPA to add nine upwind states, 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.

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. We cannot determine the effect of this potential change, if any, on our operations.

Effective August 23, 2010, the USEPA implemented revisions to its primary NAAQS for SO₂ replacing the current 24-hour standard and annual standard with a one-hour standard. We cannot determine the effect of this potential change, if any, on our operations. Initial non-attainment designations were made July 25, 2013, and Pierce Township in Clermont County, which contains our co-owned unit Beckjord 6, was the only area with our operations recommended as non-attainment. Non-attainment areas will be required to meet the new standard by October 2018. We cannot determine the effect of the designations on our operations; however, Beckjord is expected to cease operations prior to the attainment date.

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

In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate GHG emissions from motor vehicles, the USEPA made a finding that CO₂ and certain other GHGs are pollutants under the CAA. Subsequently, under the CAA, the USEPA determined that CO₂ and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. This finding became effective in January 2010. Numerous affected parties have petitioned the USEPA Administrator to reconsider this decision. On April 1, 2010, the USEPA signed the “Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards” rule. Under the USEPA’s view, this is the final action that renders CO₂ and certain other GHGs “regulated air pollutants” under the CAA.

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requirements are being phased in through successive steps that may expand the scope of covered sources over time. The USEPA has issued guidance on what the best available control technology entails for the control of GHGs; and individual states are required to determine what controls are required for facilities on a case-by-case basis. Various industry groups and states petitioned the U.S. Supreme Court to review the D.C. Circuit Court’s recent decision to uphold the USEPA’s endangerment finding, its April 2010 GHG rule and the Tailoring Rule. On October 15, 2013, the U.S. Supreme Court agreed to review several related cases addressing the USEPA’s authority to issue GHG Prevention of Significant Deterioration permits under Section 165 of the CAA. We cannot predict the outcome of this review. The ultimate impact of the Tailoring Rule on us cannot be determined at this time, but the cost of compliance could be material.

On September 20, 2013, 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. Furthermore, President Obama directed the USEPA to propose new standards, regulations, or guidelines, as appropriate, to address GHG emissions from existing EGUs under CAA subsection 111(d) by June 1, 2014, and finalize them by June 1, 2015. These latter rules may focus on energy efficiency improvements at power stations. We cannot predict the effect of these proposed or forthcoming standards on our operations.

Approximately 99% of the energy we produce is generated by coal. Our 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 our 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 us.

Litigation, Notices of Violation and Other Matters Related to Air Quality

Litigation Involving Co-Owned Stations

On June 20, 2011, the U.S. Supreme Court ruled that the USEPA’s regulation of GHGs under the CAA displaced any right that plaintiffs may have had to seek similar regulation through federal common law litigation in the court system. Although we are not named as a party to these lawsuits, we are a co-owner of coal-fired stations with Duke Energy and AEP (or their subsidiaries) that could have been affected by the outcome of these lawsuits or similar suits that may have been filed against other electric power companies, including us. Because the issue was not squarely before it, the U.S. Supreme Court did not rule against the portion of plaintiffs’ original suits that sought relief under state law.

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, we 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 our results of operations, financial condition or cash flows in the future.

Notices of Violation Involving Co-Owned Units

In November 1999, the USEPA filed civil complaints and NOVs against operators and owners of certain generation facilities for alleged violations of the CAA. Generation units operated by Duke Energy (Beckjord Unit 6) and AEP Generation (Conesville Unit 4) and co-owned by us were referenced in these actions. The Conesville complaint was resolved in 2007 as part of a larger settlement with the USEPA. Conesville was required to install FGD and SCR at the unit by the end of 2010, and those retrofits have been completed. The Beckjord complaint was also resolved through litigation. There were no penalties or settlement agreements that affected Beckjord 6.

In June 2000, the USEPA issued an NOV to the Stuart generating station operated by us (co-owned by us, 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

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(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. We cannot predict the outcome of this matter.

In December 2007, the Ohio EPA issued an NOV to Killen generating station operated by us (co-owned by Duke Energy and us) 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 (the “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. We are 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. We are unable to predict the outcome of these matters.

Notices of Violation Involving Wholly-Owned Stations

In 2007, the Ohio EPA and the USEPA issued NOVs to us for alleged violations of the CAA at the Hutchings Station. The NOVs’ alleged deficiencies relate to stack opacity and particulate emissions. On November 18, 2009, the USEPA issued an NOV to us for alleged NSR violations of the CAA at the Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. We do not believe that the two projects described in the NOV were modifications subject to NSR. As a result of the cessation of operations at the Hutchings Station discussed in the next paragraph, we believe that the USEPA is unlikely to pursue the NSR complaint.

As part of a settlement with the USEPA, we signed the CAFO that was filed on September 26, 2013 and an Administrative Consent Agreement. Together, these two agreements resolved the opacity and particulate emissions NOV at the Hutchings Station and required that all six coal-fired units at Hutchings cease operating on coal by September 30, 2013, and included an immaterial penalty and the completion of a Supplemental Environmental Project of $0.2 million within one year. The units were disabled for coal operations prior to September 30, 2013.

We also resolved all issues associated with the Ohio EPA NOV through a settlement signed October 4, 2013. The settlement included the payment of an immaterial penalty.

Environmental Matters Related to Water Quality, Waste Disposal and Ash Ponds

Clean Water Act – Regulation of Water Intake

On July 9, 2004, the USEPA issued final rules pursuant to the Clean Water Act governing existing facilities that have cooling water intake structures. The rules required an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal. A number of parties appealed the rules. In April 2009, the U.S. Supreme Court ruled that the USEPA did have the authority to compare costs with benefits in determining best technology available. The USEPA released new proposed regulations on March 28, 2011, which were published in the Federal Register on April 20, 2011. We submitted comments to the proposed regulations on August 17, 2011. The USEPA is required pursuant to a settlement agreement to issue a final rule by April 17, 2014. On April 16, 2014, the agency released a letter sent to the Court indicating the final rulemaking would be completed by May 16, 2014. On May 19, 2014, the USEPA issued final regulations, establishing requirements for cooling water intake structures. We do not yet know the impact the final rules will have on our operations.

Clean Water Act – Regulation of Water Discharge

In December 2006, we submitted a renewal application for the Stuart 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 our request, a public hearing was held on March 23, 2011, where we presented our 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.

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The draft permit required us, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of our discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system. We 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 we 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, we appealed various aspects of the final permit to the Environmental Review Appeals Commission and hearing before the commission on the appeal is scheduled for August 2014. The outcome of the appeal could have a material effect on our operations.

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. Subsequent to the information collection effort, it was anticipated that the USEPA would release a proposed rule by mid-2012 with a final regulation in place by early 2014. The proposed rule was released on June 7, 2013, with a deadline for a final rule on May 22, 2014. On December 16, 2013, the USEPA filed a status report that indicated that the agency is negotiating for an extension of time to finalize proposed revisions to the rule. On April 17, 2014, the parties entered into an agreement extending the deadline for the final regulations to September 30, 2015. At present, we are unable to predict the impact this rulemaking will have on our operations.

In August 2012, we submitted an application for the renewal of the Killen Station NPDES permit which expired in January 2013. At present, the outcome of this proceeding is not known.

In January 2014, we submitted an application for the renewal of the Hutchings Station NPDES permit which expires in July 2014. At present, the outcome of this proceeding is not known.

In April 2012, we received an NOV related to the construction of the Carter Hollow landfill at the Stuart Station. The NOV indicated that construction activities caused sediment to flow into downstream creeks. In addition, the U.S. Army Corps of Engineers issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill. We installed sedimentation ponds as part of the runoff control measures to address this issue and worked with the various agencies to resolve their concerns. We signed an Administrative Order from the USEPA on May 30, 2013. A final Consent Agreement and Final Order was executed on July 8, 2013, and the previously issued permit was reinstated by the Corps on October 29, 2013.

Regulation of Waste Disposal

In September 2002, we 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, we and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (the “RI/FS”) under a Superfund Alternative Approach. In October 2005, we received a special notice letter inviting us 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. However, on August 25, 2009, the USEPA issued an Administrative Order requiring that access to our 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. We 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 us and numerous other defendants alleging that we 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 us that related to allegations that chemicals used by us at our 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 us that were allegedly directly delivered by truck to the landfill. Discovery, including depositions of our past and present employees, was conducted in 2012. On February 8, 2013, the Court granted our 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. That summary judgment ruling was appealed on March 4, 2013 and the appeal is pending. We are unable to predict the outcome of the appeal.

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Additionally, the Court’s ruling does not address future litigation that may arise with respect to actual remediation costs. While we are unable to predict the outcome of these matters, if we were required to contribute to the clean-up of the site, it could have a material adverse effect on our operations.

Beginning in mid-2012, the USEPA began investigating whether explosive or other dangerous conditions exist under structures located at or near the South Dayton Dump landfill site. In October 2012, we received a request from the PRP group’s consultant to conduct additional soil and groundwater sampling on our service center property. After informal discussions with the USEPA, we complied with this sampling request and the sampling was conducted in February 2013. On February 28, 2013, the plaintiffs group referenced above entered into an Administrative Settlement Agreement Consent Order (the “ASACO”) that establishes procedures for further sub-slab testing under structures at the South Dayton Dump landfill site and remediation of vapor intrusion issues relating to trichloroethylene (TCE), perchloroethylene (PCE), and methane. On April 16, 2013, the plaintiffs group filed a new complaint in the United States District Court for the Southern District of Ohio against us and 34 other defendants alleging that we share liability for these costs. We have opposed the allegations that we bear any responsibility under the February 2013 ASACO and will actively oppose any attempt that the plaintiffs group may have to expand the scope of the new complaint to resurrect issues dismissed by the Court in February 2013 under the first complaint. A motion to dismiss portions of this second complaint relating to alleged migration of chemicals from our property to the landfill was denied February 18, 2014, as were motions filed by us and others to dismiss other portions of the complaint that were viewed by defendants as identical to the allegations dismissed in the first complaint proceeding. The Judge found that there were differences in the allegations and is permitting those allegations to proceed.

Limited discovery has been permitted pending resolution of the motion including some depositions of our former employees during 2013 and into 2014. We cannot predict the outcome of this proceeding.

In December 2003, we 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 us does not demonstrate that we contributed hazardous substances to the site. While we are unable to predict the outcome of this matter, if we were required to contribute to the clean-up of the site, it could have a material adverse effect on our 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 us. While the USEPA previously indicated that the official release date for a proposed rule was in April 2013, it has been delayed, likely until late 2014. At present, we are unable to predict the impact this initiative will have on our 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. We are unable to predict whether there will be additional USEPA action relative to our 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. We submitted comments on the draft report in June 2012. On March 14, 2013, we received the final report on the inspection of the Killen Station ash pond inspection from the USEPA which included recommended actions. We have submitted a response with our actions to the USEPA. We are unable to predict the outcome this inspection will have on our operations.

There has been increasing advocacy to regulate coal combustion byproducts under the 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. Litigation has been filed by several groups seeking a court-ordered deadline for the issuance of a final rule which the USEPA has opposed. On January 29, 2014, the parties to the litigation entered into a consent decree setting forth the USEPA’s obligation to sign, by December 19, 2014, a notice for publication in the

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Federal Register taking action on the Agency’s proposed Subtitle D option. The decree does not require Subtitle D regulation of coal combustion byproducts – it only requires the Agency to decide by that date whether or not to adopt the Subtitle D option. At present, the timing for a final rule regulating coal combustion byproducts cannot be determined. We are unable to predict the financial effect of this regulation, but if coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse effect on our operations.

Notice of Violation Involving Co-Owned Units

On September 9, 2011, we received an NOV from the USEPA with respect to our 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 us with certain provisions of the RCRA, the Clean Water Act NPDES permit program and the station’s storm water pollution prevention plan. The notice requested that we respond with the actions we have subsequently taken or plan to take to remedy the USEPA’s findings and ensure that further violations will not occur, which was done in October 2011. Based on our review of the findings, although there can be no assurance, we believe that the notice will not result in any material effect on our results of operations, financial condition or cash flows.

LEGAL AND OTHER MATTERS

In February 2007, we filed a lawsuit against a coal supplier seeking damages incurred due to the supplier’s failure to supply approximately 1.5 million tons of coal to two commonly-owned units under a coal supply agreement, of which approximately 570 thousand tons was our share. We obtained replacement coal to meet our needs. The supplier has denied liability, and is currently in federal bankruptcy proceedings in which we are participating as an unsecured creditor. We are unable to determine the ultimate resolution of this matter. We have not recorded any assets relating to possible recovery of costs in this lawsuit.

Capital Expenditures for Environmental Matters

Our environmental capital expenditures were approximately $2.0 million, $8.0 million and $12.0 million in 2013, 2012 and 2011, respectively. We have budgeted $11.0 million in environmental related capital expenditures for 2014.

ELECTRIC SALES AND REVENUES

The following table sets forth our electric sales and revenues for the years ended December 31, 2013, 2012 and 2011, respectively.

	Year ended December 31, 2013		Year ended December 31, 2012		Year ended December 31, 2011
Electric sales (millions of kWh)^(a)		19,423		15,606		15,599
Billed electric customers (end of period)		514,926		513,282		513,383

(a)

We sold 5,874 million kWh, 6,201 million kWh and 5,731 million kWh of power to DPLER (a subsidiary of DPL) for the years ended December 31, 2013, 2012 and 2011, respectively.

The following table sets forth our electric sales and revenues for the three months ended March 31, 2014 and 2013, respectively.

	Three months ended March 31,
	2014		2013
Electric sales (millions of kWh)^(a)		5,314		4,480
Billed electric customers (end of period)		515,748		514,089

(a)

We sold 1,604 million kWh and 1,397 million kWh of power to DPLER during the three months ended March 31, 2014 and 2013, respectively.

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DESCRIPTION OF THE NEW BONDS

General

The statements herein concerning the New Bonds and the Mortgage are a summary and do not purport to be complete. They make use of defined terms and are qualified in their entirety by express reference to the definitions in, and the appropriate sections and articles of, the Mortgage (including the below-referenced Forty-Seventh Supplemental Indenture), a copy of which is included as an exhibit to the registration statement on Form S-4 of which this prospectus forms a part.

The Old Bonds were, and the New Bonds are, to be issued under the First and Refunding Mortgage, dated as of October 1, 1935, between us and The Bank of New York Mellon, as trustee (the “Trustee”), as amended and supplemented by all supplemental indentures prior to the date hereof, including a Forty-Seventh Supplemental Indenture relating to the Old Bonds and the New Bonds (collectively referred to as the “Mortgage”). All first mortgage bonds issued or to be issued under the Mortgage, including the registered first mortgage bonds offered by this prospectus, are referred to in this prospectus as “First Mortgage Bonds.”

The Old Bonds and the New Bonds will together constitute a single series of First Mortgage Bonds under the Mortgage.

The terms of the New Bonds we are issuing in this exchange offer and the Old Bonds that are outstanding are identical in all material respects, except:

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the New Bonds will have been registered under the Securities Act; and

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the New Bonds will not contain certain transfer restrictions and registration rights (including interest rate increases) that relate to the Old Bonds.

Maturity, Interest and Payment

The New Bonds will mature on September 15, 2016, and will bear interest from the date of original issuance thereof at the rate per annum set forth in their title, payable semi-annually on March 15 and September 15 of each year to bondholders of record at the close of business on the February 28 and August 31 immediately preceding the interest payment date, the first interest payment date being September 15, 2014. The amount of interest payable for any period will be computed on the basis of a 360-day year of twelve 30-day months and for any period shorter than a full month, on the basis of the actual number of days elapsed. In the event that any date on which principal or interest is payable on the New Bonds is not a business day, the payment of the principal or interest payable on such date will be made on the next succeeding day which is a business day (and without any interest or other payment in respect of any such delay), with the same force and effect as if made on the date the payment was originally payable. The term “business day” means any day, other than a Saturday or Sunday, or which is not a day on which banking institutions or trust companies in The City of New York are generally authorized or required by law, regulation or executive order to remain closed (or which is not a day on which the corporate trust office of the Trustee is closed for business). We have agreed to pay interest on any overdue principal and, if such payment is enforceable under applicable law, on any overdue installment of interest on the New Bonds at the rate per annum set forth in its title.

The New Bonds will be issued only in denominations of $1,000 and integral multiples of $1,000. We will make principal, premium, if any, and interest payments on the New Bonds, other than certificated New Bonds, to Cede & Co. (as nominee of The Depository Trust Company (“DTC”)) so long as Cede & Co. is the registered owner. Disbursement of such payments to DTC’s participants is the responsibility of DTC, and disbursement of such payments to the beneficial owners of the New Bonds is the responsibility of DTC participants and indirect participants in DTC, all as described below under “—Book-Entry, Delivery and Form.” The New Bonds will not have the benefit of any sinking fund.

Optional Redemption

We may redeem the New Bonds, in whole or in part, at any time or from time to time prior to maturity, at a redemption price equal to the Make-Whole Amount, as described below, plus accrued and unpaid interest, if any, to the redemption date with respect to the New Bonds, or portion thereof, being redeemed.

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The “Make-Whole Amount” shall be equal to the greater of (i) 100% of the principal amount of the New Bonds being redeemed or (ii) as determined by the Quotation Agent, as described below, as of the redemption date, the sum of the present values of the scheduled payments of principal and interest on such New Bonds from the redemption date to the stated maturity date of the New Bonds (excluding the portion of any such interest accrued to such redemption date), discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at a discount rate equal to the Treasury Rate, as described below, plus 20 basis points.

“Treasury Rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date. The Treasury Rate shall be calculated on the third business day preceding the redemption date.

“Comparable Treasury Issue” means, with respect to any redemption date, the United States Treasury security selected by the Quotation Agent as having a maturity comparable to the time period from the redemption date to the stated maturity date of the New Bonds 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 time period. If no United States Treasury security has a maturity which is within a period from three months before to three months after the stated maturity date of the New Bonds, the two most closely corresponding United States Treasury securities shall be used as the Comparable Treasury Issue, and the Treasury Rate shall be interpolated and extrapolated on a straight-line basis, rounding to the nearest month using such securities.

“Quotation Agent” means one of the Reference Treasury Dealers selected by us and appointed to act in such role.

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

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

“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.

Notice of any redemption will be provided at least 20 days but no more than 60 days before the redemption date to each holder of New Bonds to be redeemed. If, at the time notice of redemption is given, the redemption monies are not held by the Trustee, the redemption may be made subject to receipt of such monies before the date fixed for redemption, and such notice shall be of no effect unless such monies are so received. Upon payment of the redemption price, on and after the redemption date, interest will cease to accrue on the New Bonds or portions thereof called for redemption.

Priority and Security

The New Bonds will rank equally and ratably with all other First Mortgage Bonds at any time outstanding under the Mortgage. As of December 31, 2013, including the Old Bonds, we had approximately $859.4 million aggregate principal amount of First Mortgage Bonds outstanding.

All outstanding First Mortgage Bonds will be secured, equally and ratably, by the lien of the Mortgage on substantially all properties owned by us (other than property excepted from such lien and such property as may be released from such lien in accordance with the terms of the Mortgage), and improvements, extensions and additions to, and renewals and replacements of, such properties.

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The lien under the Mortgage is subject to certain exclusions, including liens for taxes assessed but not then due or payable, vendor’s liens, liens of purchase money mortgages, liens for paving, conservancy or other assessments, any mortgage or other lien on any property hereafter acquired by us which may exist on the date of such acquisition, prior liens and excepted encumbrances. “Excepted encumbrances” include the following:

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any liens, neither assumed by us nor on which we customarily pay interest charges, existing upon real estate or rights in or relating to real estate we acquired for substation, transmission line, distribution line or right of way purposes;

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rights reserved to or vested in any municipality or public authority by the terms of any franchise, grant, license, permit or by any provision of law to purchase or recapture or to designate a purchaser of any of our property;

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rights reserved to or vested in others to take or receive any part of the power developed or generated by any of our property;

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easements or reservation in any of our property created at or before the time we acquired that property for the purpose of roads, pipe lines, transmission lines and other like purposes;

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rights reserved to or vested in any municipality or public authority to use or control or regulate any of our properties; or

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any obligations or duties affecting our property to any municipality or public authority with respect to any franchise, grant, license or permit.

The Mortgage provides that we will maintain the mortgaged property in working order and condition and equipped with suitable equipment and appliances; that we will make regular charges to expense for the establishment of reasonably adequate reserves for depreciation and will make all needed and proper repairs, retirements, renewals and replacements of the mortgaged property; that we will not charge to our property, plant and equipment accounts any expenditures that are properly chargeable to maintenance or repairs or to any other permitted expense account; and that we may promptly retire property that has permanently ceased to be used or useful in our business.

Release of Property

When not in default, we may obtain the release of any of the mortgaged and pledged property, including, without limiting the generality of the foregoing, any one or more of our heating, gas or water properties substantially as an entirety (provided, however, that our electric property shall not in any event be released substantially as an entirety and, further, that prior lien bonds deposited with the Trustee shall not be released except as provided by the Mortgage) upon deposit with the Trustee of cash equivalent to the amount (if any) by which the value of the property to be released exceeds certain credits, including the cost or fair value, whichever is less, to us of any property additions acquired or constructed prior to or concurrently with such release that have not been used as a basis to issue additional First Mortgage Bonds. Money received by the Trustee upon any release may be withdrawn against property additions or against the deposit of bonds or prior lien bonds, or at our request, may be applied to purchase First Mortgage Bonds or to redeem First Mortgage Bonds that are redeemable by their terms at that time.

“Property additions” means property acquired or constructed after September 30, 1945, to be used in the electric, natural gas, steam or water business.

“Funded property” includes property additions used to satisfy requirements of bond issuances and obligations or bond retirements.

Issuance of Additional First Mortgage Bonds

Subject to the limitations described below, the Mortgage permits us to issue an unlimited amount of First Mortgage Bonds from time to time in one or more series. All First Mortgage Bonds of one series need not be issued at the same time, and a series may be reopened for issuances of additional First Mortgage Bonds of such series. This means that we may from time to time, without the consent of the existing holders of the New Bonds, create and issue additional First Mortgage Bonds having the same terms and conditions as the New Bonds in all respects, except for issue date, issue price and, if applicable, the initial interest payment on the New Bonds. Additional First Mortgage Bonds issued in this manner will be consolidated with, and will form a single series with, the previously outstanding First Mortgage Bonds of such series, including, if applicable, the New Bonds.

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Additional First Mortgage Bonds, including additional First Mortgage Bonds of an existing series, may be issued:

(1)

upon the basis of property additions which are not then funded property in a principal amount which, together with any prior lien bonds outstanding on such property additions, will not exceed 60% of the cost or fair value to us of such property additions, whichever is less;

(2)

against deposits or retirement of prior lien bonds deducted in determining the amount of First Mortgage Bonds issuable upon the basis of property additions;

(3)

upon payment or retirement of other First Mortgage Bonds issued under the Mortgage or upon deposit with the Trustee of the money necessary for their purchase or payment, in principal amount equivalent to the First Mortgage Bonds paid or retired, or for which money has been so deposited; or

(4)

upon deposit with the Trustee of cash equal to the principal amount of the First Mortgage Bonds to be issued; such cash may be withdrawn in lieu of First Mortgage Bonds, which we may be entitled to have authenticated and delivered to us.

The issuance of additional First Mortgage Bonds is also limited by a net earnings test, under which no First Mortgage Bonds may be issued upon the basis of property additions or under certain other circumstances unless our adjusted net earnings for 12 consecutive calendar months in the 18 calendar months preceding the application for the issue of such First Mortgage Bonds shall be at least two times annual interest charges on all First Mortgage Bonds outstanding (except any for the payment of which the First Mortgage Bonds applied for are to be issued), on the additional First Mortgage Bonds and on the principal amount of all other indebtedness (except indebtedness for the payment of which the First Mortgage Bonds applied for are to be issued and indebtedness for the purchase, payment or redemption of which moneys in the necessary amount shall have been deposited with or be held by the Trustee or the trustee or other holder of a lien prior to the lien of the Mortgage upon property subject to the lien of the Mortgage with irrevocable direction so to apply the same; provided that, in the case of redemption, the notice required therefor shall have been given or have been provided for to the satisfaction of the Trustee), outstanding in the hands of the public and secured by a lien prior to the lien of the Mortgage upon property subject to the lien of the Mortgage, if said indebtedness has been assumed by us or if we customarily pay the interest upon the principal thereof.

As of December 31, 2013, the amount (the lesser of cost or fair value) of property additions which we could use as a basis for the issuance of additional First Mortgage Bonds was approximately $1,415.7 million. Under the property additions test, we would have been permitted at December 31, 2013 to issue approximately $849.4 billion of First Mortgage Bonds. In addition, at such date, approximately $618.7 million of First Mortgage Bonds would have been permitted to be issued as a result of prior bond retirements.

Modification of Mortgage

Our rights and obligations and those of the holders of the First Mortgage Bonds may be modified upon the written consent of the holders of at least a majority of the First Mortgage Bonds then outstanding, but no such modification shall extend the maturity of or reduce the rate of interest on or otherwise modify the terms of payment of principal of or interest on First Mortgage Bonds or permit the creation of any lien ranking prior to or equal with the lien of the Mortgage on any of the mortgaged property. If any proposed modification shall affect the rights of holders of the First Mortgage Bonds of one or more, but not all, series, then only holders of First Mortgage Bonds of the series to be affected shall be required to consent to or shall have authority to approve such modification. Any waiver of a completed default shall be deemed to affect the First Mortgage Bonds of all series, and, subject to the foregoing, any modification of the provisions of any sinking fund established in respect of a particular series shall be deemed to affect only the First Mortgage Bonds of that series. The determination of the Trustee as to what series of First Mortgage Bonds are affected by any modification shall be conclusive.

Events of Default

Among the events which constitute a “completed default” by us under the Mortgage are the following: (a) default in the payment of the principal of any First Mortgage Bond; (b) default for 90 days in the payment of interest on any First Mortgage Bond; (c) default for 90 days in the payment of amounts required for any sinking fund established in respect of a particular series; (d) certain events in bankruptcy, insolvency or reorganization; and (e) default, for 90 days after notice to us from the Trustee, in the performance of any other covenant, agreement or condition contained in the Mortgage. Upon the occurrence of any such completed default, the Trustee or the holders

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of not less than 25% in principal amount of the First Mortgage Bonds of all series outstanding under the Mortgage may declare the principal of, and any accrued interest on, all such First Mortgage Bonds immediately due and payable, subject to the right of the holders of a majority in principal amount of all such First Mortgage Bonds to annul such declaration if before any sale of the mortgaged property the default is cured. We are not required to furnish periodically to the Trustee evidence as to the absence of default or as to compliance with the terms of the Mortgage, but such evidence is required in connection with the issuance of any additional First Mortgage Bond under the Mortgage and in certain other circumstances. In addition, we are required by law to furnish annually to the Trustee a certificate as to compliance with all conditions and covenants under the Mortgage.

No bondholder may institute any action, suit or proceeding for any remedy under the Mortgage unless it shall have previously given to the Trustee written notice of a default by us and, in addition, (i) the holders of not less than 25% in principal amounts of the First Mortgage Bonds outstanding under the Mortgage shall have made a written request to the Trustee to exercise its powers under the Mortgage or to institute such action, suit or proceeding in its own name; (ii) such holders shall have offered to the Trustee security and indemnity satisfactory to it against the costs, expenses and liabilities to be incurred thereby and (iii) the Trustee shall have refused to exercise such powers or to institute such action in its own name or shall have failed to do so for an unreasonable time. Bondholders, however, have an absolute and unconditional right, without such notice to the Trustee, to enforce the payment of the principal of and the interest on their First Mortgage Bonds at and after the maturity thereof.

No personal liability of directors, officers, employees, managers and stockholders

No personal liability whatsoever shall attach to, or be incurred by, any incorporator or any past, present or future subscriber to capital stock, stockholder, officer or director of the Company or of any predecessor or successor corporation, or any of them, because of the incurring of the indebtedness authorized by the Mortgage, or under or by reason of any of the obligations, covenants or agreements contained in the Mortgage or in any indenture supplemental thereto or in any of the First Mortgage Bonds, or implied therefrom. Each holder of First Mortgage Bonds by accepting a First Mortgage Bond waives and releases all such liability. The waiver and release are part of the consideration for issuance of the First Mortgage Bonds. The waiver may not be effective to waive liabilities under the federal securities laws.

Satisfaction and Discharge of the Mortgage

Upon our making due provision for the payment of all First Mortgage Bonds and paying all other sums due under the Mortgage, the Mortgage shall cease to be of further effect and may be satisfied and discharged of record.

Merger, Consolidation and Sale

Subject to the conditions listed in the next paragraph, we may consolidate with or merge into any corporation having corporate authority to carry on any of the businesses of generating, manufacturing, transmitting, distributing or supplying (i) electricity or gas for light, heat, power or other purposes, (ii) steam or hot water for power or heat or other purposes or (iii) water for domestic or public use and consumption. The Mortgage also allows conveyance or transfer of all of the mortgaged and pledged property substantially as an entirety to any corporation that is lawfully entitled to acquire and operate such property.

The consolidation, merger, conveyance or transfer of all of the mortgaged and pledged property substantially as an entirety must satisfy the following conditions: (i) it must be upon such terms as to preserve and in no respect impair the lien or security of the Mortgage, or any rights or powers of the Trustee or the holders of First Mortgage Bonds; and (ii) the person formed by such consolidation, or into which we shall have been merged, or acquiring all the mortgaged and pledged property substantially as an entirety must expressly assume in writing the due and punctual payment of the principal and interest of all First Mortgage Bonds and the due and punctual performance and observance of all covenants and conditions of the Mortgage.

After such consolidation, merger, conveyance or transfer, the lien of the Mortgage will generally not cover the property of the successor corporation, other than the property that it acquires from us with certain exceptions.

Dividend Covenant

The Mortgage does not restrict our ability to pay dividends on our common stock.

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Defeasance

Any New Bonds, or any portion of the principal amount thereof, will be deemed to have been paid for all purposes of the Mortgage, and the entirety of our indebtedness in respect thereof will be deemed to have been satisfied and discharged, if there has been irrevocably deposited with the Trustee or any paying agent (other than us) for such purpose, in trust:

•

money (including funded cash not otherwise applied pursuant to the Mortgage, to the extent permitted by the Mortgage) in an amount which will be sufficient; or

•

in the case of a deposit made prior to the date on which principal is due, eligible obligations (as described below), which do not contain provisions permitting the redemption or other prepayment thereof at the option of the issuer thereof, the principal of and the interest on which when due, without any regard to reinvestment thereof, will provide monies which, together with the money, if any, deposited with or held by the trustee or such paying agent pursuant to the first bullet point, will be sufficient; or

•

a combination of options in the preceding bullet points,

which in each case, will be sufficient, without reinvestment, in the opinion of a nationally recognized investment bank, appraisal firm or firm of independent public accountants expressed in a written certification delivered to the Trustee, to pay when due the principal of and premium, if any, and interest, if any, due and to become due on such New Bonds or portions thereof. For this purpose, eligible obligations include direct obligations of, or obligations unconditionally guaranteed by, the United States of America, entitled to the benefit of the full faith and credit thereof, and certificates, depository receipts or other instruments, which may be issued by the Trustee that evidence a direct ownership interest in such obligations or in any specific interest or principal payments due in respect thereof.

Notwithstanding the foregoing, no New Bond shall be deemed to have been paid as aforesaid unless we shall have delivered to the Trustee either:

•

an opinion of counsel in the United States who is reasonably acceptable to the Trustee confirming that (i) we have received from, or there has been published by, the Internal Revenue Service a ruling or (ii) since the date of the Mortgage, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel shall confirm that, the holders of the outstanding New Bonds will not recognize income, gain or loss for federal income tax purposes as a result of such defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such defeasance had not occurred; or

•

an instrument wherein we, notwithstanding the satisfaction and discharge of our indebtedness in respect of New Bonds, shall assume the obligation (which shall be absolute and unconditional) to irrevocably deposit with the Trustee such additional sums of money, if any, or additional eligible obligations, if any, or any combination thereof, at such time or times, as shall be necessary, together with the money and/or eligible obligations theretofore so deposited, to pay when due the principal of and premium, if any, and interest due and to become due on such New Bonds or portions thereof; provided, however, that such instrument may state that our obligation to make additional deposits as aforesaid shall be subject to the delivery to us by a holder of a New Bond of a notice asserting the deficiency accompanied by an opinion of an independent public accountant of nationally recognized standing showing the calculation thereof; and

•

an opinion of tax counsel in the United States who is reasonably acceptable to the Trustee to the effect that the holders of the outstanding New Bonds will not recognize income, gain or loss for federal income tax purposes as a result of such defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such defeasance had not occurred.

Regarding the Trustee

The Trustee under the Mortgage is The Bank of New York Mellon. We, DPL, AES and their other subsidiaries also maintain various banking, lending, trust and other relationships with The Bank of New York Mellon and its affiliates.

The Mortgage provides that our obligations to compensate the Trustee and reimburse the Trustee for expenses (including any indemnity obligations) will be secured by a lien generally prior to that of the First Mortgage Bonds on the Mortgage trust estate and the proceeds thereof.

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Book-Entry, Delivery and Form

The New Bonds will be issued in the form of fully registered securities in global form (the “global securities”). The global securities will be deposited with, or on behalf of, DTC, or the depositary, and registered in the name of the depositary or its nominee.

So long as the depositary, or its nominee, is the registered holder of any global securities, the depositary or such nominee, as the case may be, will be considered the sole legal owner of such securities for all purposes under the Mortgage and the New Bonds. Except as set forth below, owners of beneficial interests in global securities will not be entitled to have such global securities registered in their names, will not receive or be entitled to receive physical delivery in exchange therefor and will not be considered to be the owners or holders of such global securities for any purpose under the New Bonds or the Mortgage. We understand that under existing industry practice, in the event an owner of a beneficial interest in a global security desires to take any action that the depositary, as the holder of such global security, is entitled to take, the depositary would authorize the participants to take such action, and that the participants would authorize beneficial owners owning through such participants to take such action or would otherwise act upon the instructions of beneficial owners owning through them.

Any payment of principal, premium, if any, or interest due on the New Bonds on any interest payment date, redemption date, or at maturity will be made available by us to the Trustee by such date. As soon as possible thereafter, the Trustee will make such payments to the depositary or its nominee, as the case may be, as the registered owner of the global securities representing such New Bonds in accordance with existing arrangements between the Trustee and the depositary.

We expect that the depositary or its nominee, upon receipt of any payment of principal, premium or interest in respect of the global securities, will credit immediately the accounts of the related participants with payments in amounts proportionate to their respective beneficial interests in the principal amount of such global security as shown on the records of the depositary. We also expect that payments by participants to owners of beneficial interests in the global securities held through such participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers in bearer form or registered in “street name” and will be the responsibility of such participants.

Transfers between participants in the depositary will be effected in the ordinary way in accordance with the depositary’s rules and will be settled in same-day funds. Transfers between Euroclear and Clearstream participants will be effected in the ordinary way in accordance with their respective rules and operating procedures.

None of us, the Trustee, or any paying agent for the global securities will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in any of the global securities or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests or for other aspects of the relationship between the depositary and its participants or the relationship between such participants and the owners of beneficial interests in the global securities owning through such participants.

Unless and until exchanged in whole or in part for securities in definitive form in accordance with the terms of the New Bonds, the global securities may not be transferred except as a whole by the depositary to a nominee of the depositary or by a nominee of the depositary to the depositary or another nominee of the depositary or by the depositary of any such nominee to a successor of the depositary or a nominee of each successor.

Although the depositary has agreed to the foregoing procedures in order to facilitate transfers of interests in the global securities among participants of the depositary, it is under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. Neither the Trustee nor we will have any responsibility for the performance by the depositary or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations. We and the Trustee may conclusively rely on, and shall be protected in relying on, instructions from the depositary for all purposes.

The global securities shall be exchangeable for corresponding certificated New Bonds registered in the name of persons other than the depositary or its nominee only if (a) the depositary (i) notifies us that it is unwilling or unable to continue as depositary for any of the global securities or (ii) at any time ceases to be a clearing agency registered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), (b) there shall have occurred and be continuing a completed default under the Mortgage with respect to the related series of bonds or (c) we execute and

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deliver to the Trustee, an order that the global securities shall be so exchangeable. Any certificated New Bonds will be issued only in fully registered form and shall be issued without coupons in minimum denominations of $1,000 and in integral multiples of $1,000 in excess thereof. Any certificated New Bonds so issued will be registered in such names as the depositary shall request.

Principal, premium, if any, and interest on all certificated New Bonds in registered form will be payable at the office or agency of the Trustee in The City of New York, except that, at our option, payment of any interest (except interest due at maturity) may be made by check mailed to the address of the person entitled thereto as such address shall appear in the security register or by wire transfer to an account maintained by the person entitled thereto as specified in the security register.

The depositary has advised us as follows: The depositary is a limited-purpose trust company organized under the laws of the State of New York, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and “a clearing agency” registered under the Exchange Act. The depositary was created to hold securities of institutions that have accounts with the depositary and to facilitate the clearance and settlement of securities transactions among its participants in such securities through electronic book-entry changes in accounts of participants, thereby eliminating the need for physical movement of securities certificates. The depositary’s participants include securities brokers and dealers (which may include the initial purchasers), banks, trust companies, clearing corporations and certain other organizations some of whom (or their representatives) own DTC. Access to the depositary’s book-entry system is also available to others such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, whether directly or indirectly.

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THE EXCHANGE OFFER

General

We hereby offer to exchange a like principal amount of New Bonds for any or all outstanding Old Bonds 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 Bonds pursuant to this exchange offer. As of the date of this prospectus, $445,000,000 aggregate principal amount of the Old Bonds are outstanding. Our obligation to accept Old Bonds 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 Bonds, which was consummated on September 19, 2013, we entered into a registration rights agreement with the initial purchasers of the Old Bonds under which we agreed:

(1)

to use our reasonable best efforts to file a registration statement on or prior to 210 days after the closing of the offering of the Old Bonds with respect to an offer to exchange the Old Bonds for a new issue of securities, with terms substantially the same as of the Old Bonds 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

(3)

to use our reasonable best efforts to consummate the exchange offer and issue the New Bonds within 300 business days after the closing of the Old Bonds 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 300 days following the issuance of the Old Bonds or (b) we have not caused to become effective a shelf registration statement by the 90th day after such obligation arises (which in no event, however, shall be earlier than the exchange offer closing deadline) (each such event referred to in clause (a) and (b) a “Registration Default”), the interest rate for the Old Bonds will increase by a rate of 0.25% per annum immediately following the occurrence of any Registration Default, and such increased rate will further increase by 0.25% per annum beginning on the 91st day following the occurrence of such Registration Default, but in no event shall such amounts exceed in the aggregate 0.50% per annum regardless of the number of Registration Defaults that have occurred and are continuing. Once we complete this exchange offer, we will no longer be required to pay additional interest on the Old Bonds.

The exchange offer is not being made to, nor will we accept tenders for exchange from, holders of Old Bonds 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 Bonds that wishes to exchange their Old Bonds for New Bonds in this exchange offer will be required to make certain representations as set forth herein.

Terms of the Exchange Offer; Period for Tendering Old Bonds

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 Bonds which are properly tendered on or prior to the expiration date, unless you have previously withdrawn them.

•

When you tender to us Old Bonds as provided below, our acceptance of the Old Bonds 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 $1,000 principal amount of Old Bonds (and $1,000 principal amount of Old Bonds in excess thereof) surrendered to us in the exchange offer, we will give you $1,000 principal amount of New Bonds (and $1,000 principal amount of New Bonds in excess thereof). Outstanding bonds may only be tendered in denominations of $1,000 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 transmit notice of the exchange offer to the holders of the Old Bonds. 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 Bonds at their addresses listed in the trustee’s security register with respect to the Old Bonds.

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The exchange offer expires at 11:59 P.M., New York City time, on July 14, 2014; 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 14, 2014 or, if extended by us, the latest time and date to which the exchange offer is extended.

•

As of the date of this prospectus, $445,000,000 aggregate principal amount of the Old Bonds was outstanding. The exchange offer is not conditioned upon any minimum principal amount of Old Bonds being tendered.

•

Our obligation to accept Old Bonds 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 Bonds, 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 Bonds previously tendered will remain subject to the exchange offer unless withdrawal rights are exercised. Any Old Bonds 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 Bonds 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 Bonds 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 the Dow Jones News Service or other similar news service.

•

Holders of Old Bonds do not have any appraisal or dissenters’ rights in connection with the exchange offer.

•

Old Bonds 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 Bonds.”

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 Bonds 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 Bonds not properly tendered or to not accept any particular Old Bonds 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 Bonds either before or after the expiration date, including the right to waive the ineligibility of any holder who seeks to tender Old Bonds in the exchange offer. Unless we agree to waive any defect or irregularity in connection with the tender of Old Bonds for exchange, you must cure any defect or irregularity within any reasonable period of time as we shall determine.

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•

Our interpretation of the terms and conditions of the exchange offer as to any particular Old Bonds either before or after the expiration date shall be final and binding on all parties.

•

None of us, the exchange agent or any other person shall be under any duty to give notification of any defect or irregularity with respect to any tender of Old Bonds for exchange, nor shall any of them incur any liability for failure to give any notification.

Procedures for Tendering Old Bonds

What to submit and how

If you, as the registered holder of an old security, wish to tender your Old Bonds for exchange in the exchange offer, you must transmit a properly completed and duly executed letter of transmittal to The Bank of New York Mellon at the address set forth below under “Exchange Agent” on or prior to the expiration date.

In addition,

(1)

certificates for Old Bonds 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 Bonds, 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 Bonds, 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 Bonds should be sent to DP&L.

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 Bonds being surrendered for exchange are tendered

(1)

by a registered holder of the Old Bonds 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.

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 Bonds, the Old Bonds 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 Bonds and with the signature guaranteed.

If the letter of transmittal or any Old Bonds 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 us, proper evidence satisfactory to us of its authority to so act must be submitted.

Acceptance of Old Bonds for Exchange; Delivery of New Bonds

Once all of the conditions to the exchange offer are satisfied or waived, we will accept, promptly after the expiration date, all Old Bonds properly tendered and will issue the New Bonds 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.

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In all cases, we will issue New Bonds in exchange for Old Bonds that are accepted for exchange only after timely receipt by the exchange agent of:

•

certificates for Old Bonds, or

•

a timely book-entry confirmation of transfer of Old Bonds 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 Bonds for any reason included in the terms and conditions of the exchange offer or if you submit certificates representing Old Bonds in a greater principal amount than you wish to exchange, we will return any unaccepted or non-exchanged Old Bonds without expense to the tendering holder or, in the case of Old Bonds tendered by book-entry transfer into the exchange agent’s account at DTC using the book-entry transfer procedures described below, non-exchanged Old Bonds 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 Bonds 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 Bonds by causing DTC to transfer Old Bonds into the exchange agent’s account in accordance with DTC’s Automated Tender Offer Program procedures for transfer. However, the exchange for the Old Bonds so tendered will only be made after timely confirmation of book-entry transfer of Old Bonds 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 Bonds 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.

Although delivery of Old Bonds 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 Bonds 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 Bonds or not tender your Old Bonds. 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 securities until the exchange agent receives a letter of transmittal and a book-entry confirmation from DTC with respect to your securities. A copy of that form is available from the exchange agent.

Guaranteed Delivery Procedures

If you are a registered holder of Old Bonds and you want to tender your Old Bonds but your Old Bonds are not immediately available, or time will not permit your Old Bonds 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 Bonds;

•

the amount of Old Bonds 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 Bonds, 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

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•

the certificates for all physically tendered Old Bonds, 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 Bonds 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 Bonds to be withdrawn

•

the Old Bonds to be withdrawn

•

the principal amount of the Old Bonds to be withdrawn

•

if certificates for Old Bonds have been delivered to the exchange agent, the name in which the Old Bonds are registered, if different from that of the withdrawing holder

•

if certificates for Old Bonds 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 withdrawn and a signed notice of withdrawal with signatures guaranteed by an eligible institution unless you are an eligible institution.

•

if Old Bonds 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 Bonds 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 Bonds 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 Bonds and wish to re-tender them, you may do so by following one of the procedures described under “Procedures for Tendering Old Bonds” 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 Bonds in exchange for, any Old Bonds 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.

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Exchange Agent

The Bank of New York Mellon 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 or Certified Mail:
The Bank of New York Mellon
111 Sanders Creek Parkway
East Syracuse, NY 13057
Attention: Corporate Trust – Reorg

By Facsimile Transmissions:
732-667-9408
Attn: Adam DeCapio

To Confirm by Telephone
or for Information:
315-414-3360

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.

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 Bonds in our accounting records at the same carrying value as the Old Bonds, 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 bonds.

Transfer Taxes

Holders who tender their Old Bonds for exchange will not be obligated to pay any transfer taxes in connection therewith, except that holders who instruct us to register New Bonds in the name of, or request that Old Bonds 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 Bonds

Under existing interpretations of the staff of the SEC contained in several no-action letters to third parties, the New Bonds 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.

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However, any purchaser of Old Bonds who is an “affiliate” of DP&L or who intends to participate in the exchange offer for the purpose of distributing the New Bonds

(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 Bonds 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 Bonds will represent that:

(1)

it is not our “affiliate”;

(2)

any New Bonds 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 Bonds.

In addition, in connection with any resales of New Bonds, 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 & 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 Bonds, other than a resale of an unsold allotment from the original sale of the Old Bonds, 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 Bonds.

Failure to Exchange

Holders of Old Bonds who do not exchange their Old Bonds for New Bonds under the exchange offer will remain subject to the restrictions on transfer of such Old Bonds as set forth in the legend printed on the Old Bonds as a consequence of the issuance of the Old Bonds 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 Bonds.

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.

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CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The exchange of an Old Bond for a New Bond pursuant to the exchange offer will not constitute a “significant modification” of the Old Bold for United States federal income tax purposes and, accordingly, the New Bond received will be treated as a continuation of the Old Bond in the hands of such holder. As a result, there will be no United States federal income tax consequences to a holder who exchanges an Old Bond for a New Bond pursuant to the exchange offer and any such holder will have the same adjusted tax basis and holding period in the New Bond as it had in the Old Bond immediately before the exchange. A holder who does not exchange its Old Bond for a New Bond pursuant to the exchange offer will not recognize any gain or loss, for United States federal income tax purposes, upon consummation of the exchange offer.

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PLAN OF DISTRIBUTION

Each broker-dealer that receives New Bonds for its own account in the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of New Bonds. 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 Bonds received in exchange for Old Bonds where Old Bonds 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 Bonds received by it in exchange for Old Bonds.

We will not receive any proceeds from any sale of New Bonds by broker-dealers.

New Bonds 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 Bonds; 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:

•

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 Bonds.

Any broker-dealer that resells New Bonds 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 Bonds may be considered to be an “underwriter” within the meaning of the Securities Act. Any profit on any resale of those New Bonds 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.

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VALIDITY OF SECURITIES

Michael S. Mizell, General Counsel of The Dayton Power and Light Company, and Skadden, Arps, Slate, Meagher & Flom LLP will opine for us on whether the New Bonds are valid and binding obligations of The Dayton Power and Light Company.

EXPERTS

The financial statements and schedule of The Dayton Power and Light Company at December 31, 2013 and 2012, and for each of the years ended December 31, 2013 and 2012 appearing in this Prospectus and 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.

The financial statements and “Schedule II - Valuation and Qualifying Accounts” of The Dayton Power and Light Company for the period ended December 31, 2011, have been included herein and the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

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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 Bonds. 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 DP&L and the New Bonds, 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.

We file and furnish annual, quarterly and current reports and other information with the SEC. The public may read and copy the registration statement, including the exhibits and schedules thereto, and any reports or other information that we file with the SEC at the SEC’s Public Reference Room, 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public at the web site maintained by the SEC at http://www.sec.gov. You may also obtain a copy of the registration statement or any other reports that we file with the SEC from DPL’s website, www.dplinc.com, or at no cost by writing or telephoning us at the following address:

The Dayton Power and Light Company
Financial Activities
1065 Woodman Drive
Dayton, Ohio 45432
(937) 224-6000

DPL’s 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.

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INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm (Ernst & Young LLP)	F-2
Report of Independent Registered Public Accounting Firm (KPMG LLP)	F-3
Statements of Results of Operations for each of the three years in the period ended December 31, 2013	F-4
Statements of Other Comprehensive Income / (Loss) for each of the three years in the period ended December 31, 2013	F-5
Statements of Cash Flows for each of the three years in the period ended December 31, 2013	F-6
Balance Sheets at December 31, 2013 and 2012	F-8
Statement of Shareholder’s Equity for each of the three years in the period ended December 31, 2013	F-10
Notes to Financial Statements	F-11
Schedule II – Valuation and Qualifying Accounts	F-66
Condensed Statements of Results of Operations for the three month periods ended March 31, 2014 and 2013	F-67
Condensed Statements of Comprehensive Income for the three month periods ended March 31, 2014 and 2013	F-68
Condensed Statements of Cash Flows for the three month periods ended March 31, 2014 and 2013	F-69
Condensed Balance Sheets at March 31, 2014 and 2013	F-70
Notes to Condensed Financial Statements (Unaudited)	F-72

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Report of Independent Registered Public Accounting Firm

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

We have audited the accompanying balance sheets of The Dayton Power and Light Company (DP&L) as of December 31, 2013 and 2012, and the related statements of Results of Operations, Comprehensive Income/(Loss), Cash Flows, and Shareholders’ Equity for the years ended December 31, 2013 and 2012. Our audit also included the consolidated financial statement schedule “Schedule II – Valuation and Qualifying Accounts” for the years ended December 31, 2013 and 2012. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of DP&L at December 31, 2013 and 2012, and the results of its operations and its cash flows for the years ended December 31, 2013 and 2012 , 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

March 4, 2014
Louisville, Kentucky

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Report of Independent Registered Public Accounting Firm

The Board of Directors
The Dayton Power and Light Company:

We have audited the accompanying statements of results of operations, comprehensive income / (loss), cash flows and shareholder’s equity of The Dayton Power and Light Company (DP&L) for the year ended December 31, 2011. In connection with our audit of the financial statements, we also have audited the financial statement schedule, ”Schedule II – Valuation and Qualifying Accounts” for the year ended December 31, 2011. These financial statements and financial statement schedule are the responsibility of DP&L’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit.

We conducted our audit 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements of DP&L referred to above present fairly, in all material respects, the results of its operations and its cash flows for the year ended December 31, 2011, 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/ KPMG LLP

Philadelphia, Pennsylvania
March 27, 2012

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THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF RESULTS OF OPERATIONS

	Year ended December 31,
	2013			2012			2011
$ in millions
Revenues	$	1,551.5		$	1,531.8		$	1,677.7

Cost of revenues:
Fuel		362.5			354.9			380.6
Purchased power		381.9			309.5			401.6
Total cost of revenues		744.4			664.4			782.2

Gross margin		807.1			867.4			895.5

Operating expenses:
Operation and maintenance		362.1			385.9			364.8
Depreciation and amortization		140.2			141.3			134.9
General taxes		76.4			74.4			75.9
Fixed asset impairment		86.0			80.8			—
Total operating expenses		664.7			682.4			575.6

Operating income		142.4			185.0			319.9

Other income / (expense), net
Investment income		2.0			2.3			17.3
Interest expense		(37.2	)		(39.1	)		(38.2	)
Other deductions		(5.0	)		(1.9	)		(1.6	)
Total other expense, net		(40.2	)		(38.7	)		(22.5	)

Earnings (loss) from operations before income tax		102.2			146.3			297.4

Income tax expense		18.6			55.1			104.2

Net income		83.6			91.2			193.2

Dividends on preferred stock		0.9			0.9			0.9

Earnings on common stock	$	82.7		$	90.3		$	192.3

See Notes to Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)

	Year ended December 31,
	2013			2012			2011
$ in millions
Net income	$	83.6		$	91.2		$	193.2

Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax benefit / (expense) of $0.9, $(0.2) and $4.3 for each respective period		(1.6	)		0.5			(7.8	)
Reclassification to earnings, net of income tax benefit / (expense) of $(0.7), $0.0 and $0.0 for each respective period		1.4			(0.1	)		—
Total change in fair value of available-for-sale securities		(0.2	)		0.4			(7.8	)

Derivative activity:
Change in derivative fair value, net of income tax benefit / (expense) of $(0.6), $1.6 and $0.5 for each respective period		1.0			(3.0	)		(1.2	)
Reclassification of earnings, net of income tax benefit / (expense) of $(2.5), $0.5 and $0.1 for each respective period		2.6			(3.4	)		(0.2	)
Total change in fair value of derivatives		3.6			(6.4	)		(1.4	)

Pension and postretirement activity:
Prior service cost for the period, net of income tax benefit / (expense) of $(0.2), $(0.5) and $(0.4) for each respective period		0.5			0.8			0.5
Net loss for the period, net of income tax benefit / (expense) of $(1.9), $0.8 and $5.4 for each respective period		4.3			(1.5	)		(8.0	)
Reclassification to earnings, net of income tax benefit / (expense) of $(1.9), $(1.5) and $(1.5) for each respective period		3.8			2.7			2.3
Total change in unfunded pension and postretirement obligation		8.6			2.0			(5.2	)

Other comprehensive income / (loss)		12.0			(4.0	)		(14.4	)

Net comprehensive income	$	95.6		$	87.2		$	178.8

See Notes to Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF CASH FLOWS

	Year ended December 31,
	2013			2012			2011
$ in millions
Cash flows from operating activities:
Net income	$	83.6		$	91.2		$	193.2
Adjustments to reconcile Net income (loss) to Net cash from operating activities
Depreciation and amortization		140.2			141.3			134.9
Deferred income taxes		(16.8	)		3.6			50.7
Gain on liquidation of DPL stock, held in trust		—			—			(14.6	)
Fixed-asset impairment		86.0			80.8			—
Recognition of deferred SECA revenue		—			(17.8	)		—
Changes in certain assets and liabilities:
Accounts receivable		15.0			20.9			5.3
Inventories		27.2			14.2			(11.8	)
Prepaid taxes		0.4			0.1			8.1
Taxes applicable to subsequent years		(1.8	)		5.2			(9.0	)
Deferred regulatory costs, net		7.8			(1.5	)		(12.6	)
Accounts payable		(5.9	)		(15.3	)		7.1
Accrued taxes payable		(9.1	)		(8.5	)		15.2
Accrued interest payable		(3.4	)		5.2			0.2
Pension, retiree and other benefits		1.8			28.5			(24.0	)
Unamortized investment tax credit		(2.5	)		(2.5	)		(2.5	)
Other		12.8			(5.6	)		24.0
Net cash from operating activities		335.3			339.8			364.2

Cash flows from investing activities:
Capital expenditures		(122.1	)		(195.5	)		(204.5	)
Decrease / (increase) in restricted cash		(2.3	)		2.9			(3.8	)
Purchase of renewable energy credits		(3.9	)		(5.4	)		(4.4	)
Proceeds from sale of property - other		0.8			0.2			—
Insurance proceeds		14.2			—			—
Proceeds from liquidation of DPL stock, held in trust		—			—			26.9
Other investing activities, net		(1.2	)		0.3			0.8
Net cash from investing activities		(114.5	)		(197.5	)		(185.0	)

See Notes to Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF CASH FLOWS (continued)

	Year ended December 31,
	2013			2012			2011
$ in millions
Cash flows from financing activities
Dividends paid on common stock to parent		(190.0	)		(145.0	)		(220.0	)
Dividends paid on preferred stock		(0.9	)		(0.9	)		(0.9	)
Retirement of long-term debt		(470.1	)		(0.1	)		(0.1	)
Cash contribution from parent		—			—			20.0
Issuance of long-term debt		445.0			—			—
Deferred financing costs		(10.4	)		—			—
Borrowings from revolving credit facilities		—			—			50.0
Repayment of borrowings from revolving credit facilities		—			—			(50.0	)
Net cash from financing activities		(226.4	)		(146.0	)		(201.0	)

Cash and cash equivalents:
Net change		(5.6	)		(3.7	)		(21.8	)
Balance at beginning of period		28.5			32.2			54.0
Cash and cash equivalents at end of period	$	22.9		$	28.5		$	32.2

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	41.5		$	35.1		$	39.2
Income taxes (refunded) / paid, net	$	(20.3	)	$	61.9		$	13.9
Non-cash financing and investing activities:
Accruals for capital expenditures	$	14.7		$	16.7		$	26.5
Long-term liability incurred for the purchase of plant assets	$	—		$	—		$	18.7

See Notes to Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY
BALANCE SHEETS

	December 31, 2013			December 31, 2012
$ in millions
ASSETS

Current assets:
Cash and cash equivalents	$	22.9		$	28.5
Restricted funds		13.0			10.7
Accounts receivable, net (Note 3)		147.5			160.0
Inventories (Note 3)		81.7			108.9
Taxes applicable to subsequent years		68.5			66.7
Regulatory assets, current (Note 4)		20.8			18.3
Other prepayments and current assets		32.5			33.0
Total current assets		386.9			426.1

Property, plant and equipment:
Property, plant and equipment		5,105.3			5,249.0
Less: Accumulated depreciation and amortization		(2,448.1	)		(2,516.3	)
		2,657.2			2,732.7
Construction work in process		60.9			87.8
Total net property, plant and equipment		2,718.1			2,820.5

Other non-current assets:
Regulatory assets, non-current (Note 4)		159.7			185.5
Intangible assets, net of amortization (Note 1)		8.3			9.0
Other deferred assets		40.1			23.1
Total other non-current assets		208.1			217.6

Total Assets	$	3,313.1		$	3,464.2

See Notes to Financial Statements.

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TABLE OF CONTENTS

THE DAYTON POWER AND LIGHT COMPANY
BALANCE SHEETS

	December 31, 2013			December 31, 2012
$ in millions
LIABILITIES AND SHAREHOLDER'S EQUITY

Current liabilities:
Current portion - long-term debt (Note 6)	$	0.2		$	570.4
Accounts payable		73.9			79.1
Accrued taxes		81.0			92.2
Accrued interest		9.6			13.1
Customer security deposits		33.1			35.2
Regulatory liabilities, current (Note 4)		—			0.1
Other current liabilities		59.7			52.1
Total current liabilities		257.5			842.2

Non-current liabilities:
Long-term debt (Note 6)		876.9			332.7
Deferred taxes (Note 7)		632.3			652.0
Taxes payable		76.5			66.0
Regulatory liabilities, non-current (Note 4)		121.1			117.3
Pension, retiree and other benefits (Note 8)		51.6			61.6
Unamortized investment tax credit		24.9			27.4
Other deferred credits		45.4			43.0
Total non-current liabilities		1,828.7			1,300.0

Redeemable preferred stock		22.9			22.9

Commitments and contingencies (Note 14)

Common shareholder's equity:
Common stock, par value of $0.01 per share		0.4			0.4
50,000,000 shares authorized, 41,172,173 shares issued and outstanding
Other paid-in capital		803.5			803.3
Accumulated other comprehensive loss		(26.7	)		(38.7	)
Retained earnings		426.8			534.1
Total common shareholder's equity		1,204.0			1,299.1

Total Liabilities and Shareholder's Equity	$	3,313.1		$	3,464.2

See Notes to Financial Statements.

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TABLE OF CONTENTS

THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF SHAREHOLDER'S EQUITY

$ in millions (except Outstanding Shares)	Common Stock^(a)				Other Paid-in Capital			Accumulated Other Comprehensive Income / (Loss)			Retained Earnings			Total
$ in millions (except Outstanding Shares)	Outstanding Shares		Amount		Other Paid-in Capital						Retained Earnings			Total
Beginning balance		41,172,173	$	0.4	$	782.5		$	(20.3	)	$	616.9		$	1,379.5

Year ended December 31, 2011
Total comprehensive income (loss)									(14.4	)		193.2			178.8
Common stock dividends												(220.0	)		(220.0	)
Preferred stock dividends												(0.9	)		(0.9	)
Parent company capital contribution						20.0									20.0
Tax effects to equity						1.4									1.4
Employee / Director stock plans						(5.4	)								(5.4	)
Other						4.7						(0.2	)		4.5
Ending balance		41,172,173		0.4		803.2			(34.7	)		589.0			1,357.9

Year ended December 31, 2012
Total comprehensive income (loss)									(4.0	)		91.2			87.2
Common stock dividends												(145.0	)		(145.0	)
Preferred stock dividends												(0.9	)		(0.9	)
Other						0.1						(0.2	)		(0.1	)
Ending balance		41,172,173		0.4		803.3			(38.7	)		534.1			1,299.1

Year ended December 31, 2013
Total comprehensive income (loss)									12.0			83.6			95.6
Common stock dividends												(190.0	)		(190.0	)
Preferred stock dividends												(0.9	)		(0.9	)
Other						0.2									0.2
Ending balance		41,172,173	$	0.4	$	803.5		$	(26.7	)	$	426.8		$	1,204.0

(a)

$0.01 par value, 50,000,000 shares authorized.

See Notes to Financial Statements.

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TABLE OF CONTENTS

The Dayton Power and Light Company
Notes to Financial Statements

Note 1 – Overview and Summary of Significant Accounting Policies

Description of Business

DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail service are still regulated. DP&L has the exclusive right to provide such service to its more than 515,000 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 seven 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 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.

DP&L filed a generation separation application with the PUCO at the end of December 2013, as required in its ESP order and on February 25, 2013, filed a supplemental application. In the supplemental application, DP&L reaffirmed its commitment to separate the generation assets on or before May 31, 2017. DP&L continues to look at multiple options to effectuate the separation including transfer into a new unregulated affiliate of DPL or through a sale.

On November 28, 2011, DP&L’s parent company DPL was acquired by AES in the Merger and DPL became a wholly-owned subsidiary of AES. See Note 2 for more information. Following the Merger of DPL and Dolphin Subsidiary II, Inc., DPL became an indirectly wholly-owned subsidiary of AES.

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

DP&L employed 1,218 people as of December 31, 2013. Approximately 62% of all employees are under a collective bargaining agreement which expires on October 31, 2014.

Financial Statement Presentation

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

Certain immaterial amounts from prior periods, including derivative assets and liabilities and restricted cash, have been reclassified to conform to the current period presentation.

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

Revenue Recognition

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our statements of results of

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TABLE OF CONTENTS

The Dayton Power and Light Company
Notes to Financial Statements

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. These power sales and purchases are reported on a net hourly basis as revenues or purchased power on our statements of results of operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity.

Allowance for Uncollectible Accounts

We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues.

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. Property, plant and equipment 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, $4.0 million, and $4.4 million for the years ended December 31, 2013, 2012 and 2011, 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.

At December 31, 2013, DP&L did not have any material plant acquisition adjustments or other plant-related adjustments.

Repairs and Maintenance

Costs associated with maintenance activities, primarily 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 DP&L’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. The effect of this impairment will be to reduce future depreciation related to these stations by approximately $3.8 million per year.

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TABLE OF CONTENTS

The Dayton Power and Light Company
Notes to Financial Statements

In the third quarter of 2012, a series of events led DP&L management to conclude that there was an impairment in the value of certain generating stations. See Note 15 for more information. The effect of this impairment will be to reduce future depreciation related to these stations by approximately $7.1 million per year. The effect in the years ended December 31, 2013 and 2012 was a reduction of approximately $5.4 million and $1.8 million, respectively.

For DP&L’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 4.4% in 2013, 4.2% in 2012 and 2.6% in 2011.

The following is a summary of DP&L’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2013 and December 31, 2012:

	December 31,
	2013		Composite Rate			2012		Composite Rate
$ in millions
Regulated:
Transmission	$	388.3		2.3	%	$	380.9		2.4	%
Distribution		1,528.2		3.5	%		1,480.7		3.4	%
General		111.1		6.2	%		100.0		5.4	%
Non-depreciable		60.8	N/A				60.1	N/A
Total regulated		2,088.4					2,021.7
Unregulated:
Production / Generation		3,002.1		5.2	%		3,210.8		4.9	%
Non-depreciable		14.8	N/A				16.5	N/A
Total unregulated		3,016.9					3,227.3
Total property, plant and equipment in service	$	5,105.3		4.4	%	$	5,249.0		4.2	%

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 consisted 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 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, 2011	$	18.8
Calendar 2012
Accretion expense		0.9
Settlements		(0.4	)
Estimated cash flow revisions		(0.1	)
Balance at December 31, 2012		19.2
Calendar 2013
Accretion expense		1.0
Settlements		(0.3	)
Balance at December 31, 2013	$	19.9

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TABLE OF CONTENTS

The Dayton Power and Light Company
Notes to Financial Statements

Asset Removal Costs

We continue to record cost of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $114.9 million and $112.1 million in estimated costs of removal at December 31, 2013 and 2012, 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 4 for additional information.

Changes in the Liability for Transmission and Distribution Asset Removal Costs

$ in millions
Balance at December 31, 2011	$	112.4
Calendar 2012
Additions		10.1
Settlements		(10.4	)
Balance at December 31, 2012		112.1
Calendar 2013
Additions		22.0
Settlements		(19.2	)
Balance at December 31, 2013	$	114.9

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, such as with our CCEM energy efficiency program. 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 4 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 consist of emission allowances and renewable energy credits. Emission allowances are carried on a first-in, first out (FIFO) basis for purchased emission allowances. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded

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TABLE OF CONTENTS

The Dayton Power and Light Company
Notes to Financial Statements

as a component of our fuel costs and are reflected in Operating income when realized. Beginning in January 2010, part of the gains on emission allowances were used to reduce the overall fuel rider charged to our SSO retail customers. Emission allowances are amortized as they are used in our operations. Renewable energy credits are amortized as they are used or retired.

Prior to the Merger date, emission allowances and renewable energy credits were carried as inventory. Emission allowances and renewable energy credits are now carried as intangibles in accordance with AES’ policy.

Income Taxes

GAAP 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. Deferred tax assets are recognized for deductible temporary differences. 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. Prior to the Merger, DPL and its subsidiaries filed a consolidated U.S. federal income tax return. 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: available-for-sale and held-to-maturity. 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 are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements of Results of Operations in accordance with AES policy. The amounts for the years ended December 31, 2013, 2012 and 2011 were $50.5 million, $50.5 million and $53.7 million, respectively.

Share-Based Compensation

We measure the cost of employee services received and paid with equity instruments based on the fair value of such equity instrument on the grant date. This cost is recognized in results of operations over the period that employees are required to provide service. Liability awards are initially recorded based on the fair value of equity instruments and are to be re-measured for the change in stock price at each subsequent reporting date until the liability is ultimately settled. The fair value for employee share options and other similar instruments at the grant date are estimated using option-pricing models and any excess tax benefits are recognized as an addition to paid-in capital. The reduction in income taxes payable from the excess tax benefits is presented in the statements of cash flows within Cash flows from financing activities. See Note 11 for additional information. As a result of the Merger, discussed in Note 2, vesting of all share-based awards was accelerated as of the Merger date, and none are in existence at December 31, 2013 or 2012.

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.

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TABLE OF CONTENTS

The Dayton Power and Light Company
Notes to Financial Statements

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 they are designated as a cash flow hedge of a forecasted transaction or qualify 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 and MTM accounting when the hedge or a portion of the hedge is not effective. 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 to DP&L and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, property damage, and directors’ and officers’ liability. 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 reserves for claims costs below certain coverage thresholds of third-party providers. We record these additional insurance and claims costs of approximately $18.8 million and $17.7 million at December 31, 2013 and 2012, 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 costs at DP&L are actuarially determined based on 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.

Related Party Transactions

In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL. All material intercompany accounts and transactions are eliminated in DPL’s Consolidated Financial Statements.

Effective December 22, 2013, AES US 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 the AES U.S. Strategic Business Unit (“U.S. SBU”). The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable distribution. This includes ensuring that the regulatory utilities served, including DP&L, are not subsidizing costs incurred for the benefit of non-regulated businesses.

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The Dayton Power and Light Company
Notes to Financial Statements

The following table provides a summary of these transactions:

	Years ended December 31,
	2013			2012			2011
$ in millions
DP&L revenues:
Sales to DPLER^(a)	$	345.8		$	350.8		$	327.0
Sales to MC Squared^(a)	$	108.1		$	40.0		$	—
DP&L Operation & Maintenance Expenses:
Premiums paid for insurance services provided by MVIC^(b)	$	(2.9	)	$	(2.6	)	$	(3.1	)
Expense recoveries for services provided to DPLER^(c)	$	5.2		$	4.0		$	4.6
DP&L Customer security deposits:
Deposits received from DPLER^(d)	$	19.2		$	20.2		$	—

(a)

DP&L sells power to DPLER and MC Squared to satisfy the electric requirements of their retail customers. The revenue dollars associated with sales to DPLER and MC Squared are recorded as wholesale revenues in DP&L’s Financial Statements. The increase in DP&L’s sales to DPLER during the year ended December 31, 2012, compared to the year ended December 31, 2011 is primarily due to customers electing to switch their generation service from DP&L to DPLER. DP&L started selling physical power to MC Squared during June 2012 and became their sole source of power in September 2012.

(b)

MVIC, a wholly-owned captive insurance subsidiary of DPL, provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC.

(c)

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

(d)

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

Recently Adopted Accounting Standards

Offsetting Assets and Liabilities

In December 2011, the FASB issued ASU 2011-11 “Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11) effective for interim and annual reporting periods beginning on or after January 1, 2013. We adopted this ASU on January 1, 2013. This standard was clarified by ASU 2013-01 “Scope Clarification of Disclosures about Offsetting Assets and Liabilities”, which also was effective on January 1, 2013. This standard updates FASC Topic 210 “Balance Sheet.” ASU 2011-11 updates the disclosures for financial instruments and derivatives to provide more transparent information around the offsetting of assets and liabilities. Entities are required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and/or subject to an agreement similar to a master netting agreement. In ASU 2013-01, the FASB clarified that the disclosures were not intended to include trade receivables and other contracts for financial instruments that may be subject to a master netting arrangement. We adopted this rule, which resulted in enhanced disclosures, but it did not have an effect on our overall results of operations, financial position or cash flows.

Testing Indefinite-Lived Intangible Assets for Impairments

In July 2012, the FASB issued ASU 2012-02 “Testing Indefinite-Lived Intangible Assets for Impairment” (ASU 2012-02) effective for interim and annual impairment tests performed for fiscal years beginning after September 15, 2012. We adopted this ASU on January 1, 2013. This standard updates FASC Topic 350 “Intangibles-Goodwill and Other.” ASU 2012-02 permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test in accordance with FASC Subtopic 350-30. We adopted this rule but it did not have an effect on our overall results of operations, financial position or cash flows.

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TABLE OF CONTENTS

The Dayton Power and Light Company
Notes to Financial Statements

Comprehensive Income

The FASB recently issued ASU 2013-02 “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income” effective for annual and interim periods beginning after December 15, 2012. This ASU does not change the current requirements for reporting net income or OCI in financial statements. However, this ASU requires an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the Notes, significant amounts reclassified out of AOCI by the respective line items of net income, but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. We adopted this rule, which resulted in enhanced disclosures, but it did not have an effect on our overall results of operations, financial position or cash flows.

Note 2 – Business Combination

On November 28, 2011, all of the outstanding common stock of DP&L’s parent company, DPL, was acquired by AES. In accordance with FASC 805, the assets and liabilities of DPL were valued at their fair value at the Merger date. These adjustments were “pushed down” to DPL’s records. These adjustments were not pushed down to DP&L which will continue to present its assets and liabilities on its historical cost basis. Therefore, DP&L does not need to show a Predecessor and Successor split of its financial statements.

Note 3 – Supplemental Financial Information

	December 31,
	2013			2012
$ in millions
Accounts receivable, net
Unbilled revenue	$	47.2		$	48.1
Customer receivables		58.2			62.0
Amounts due from partners in jointly-owned stations		15.8			19.7
Coal sales		—			1.6
Other		27.2			29.5
Provisions for uncollectible accounts		(0.9	)		(0.9	)
Total accounts receivable, net	$	147.5		$	160.0
Inventories
Fuel and limestone	$	42.9		$	67.3
Plant materials and supplies		37.0			39.8
Other		1.8			1.8
Total inventories, at average cost	$	81.7		$	108.9

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TABLE OF CONTENTS

The Dayton Power and Light Company
Notes to Financial Statements

Accumulated Other Comprehensive Income (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2013, 2012 and 2011 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) Components	Affected line item in the Statements of Operations	Years ended December 31,
	Affected line item in the Statements of Operations	2013			2012			2011
$ in millions
Gains and losses on Available-for-sale securities activity (Note 9):
	Other income / (deductions)	$	2.1		$	(0.1	)	$	—
	Total before income taxes		2.1			(0.1	)		—
	Tax expense		(0.7	)		—			—
	Net of income taxes		1.4			(0.1	)		—
Gains and losses on cash flow hedges (Note 10):
	Interest expense		(2.1	)		(2.5	)		(2.4	)
	Revenue		2.2			0.3			1.1
	Purchased power		5.0			(1.6	)		1.0
	Total before income taxes		5.1			(3.8	)		(0.3	)
	Tax expense		(2.5	)		0.4			0.1
	Net of income taxes		2.6			(3.4	)		(0.2	)
Amortization of defined benefit pension items (Note 8):
	Reclassification to Other income / (deductions)		5.7			4.1			2.8
	Tax benefit		(1.9	)		(1.4	)		(0.5	)
	Net of income taxes		3.8			2.7			2.3
Total reclassifications for the period, net of income taxes		$	7.8		$	(0.8	)	$	2.1

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2013 and 2012 are as follows:

	Gains / (losses) on available- for-sale securities			Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total
$ in millions
Balance January 1, 2012	$	0.6		$	9.0		$	(44.3	)	$	(34.7	)
Other comprehensive income / (loss) before reclassifications		0.5			(3.0	)		(0.7	)		(3.2	)
Amounts reclassified from accumulated other comprehensive income / (loss)		(0.1	)		(3.4	)		2.7			(0.8	)
Net current period other comprehensive income / (loss)		0.4			(6.4	)		2.0			(4.0	)
Balance December 31, 2012		1.0			2.6			(42.3	)		(38.7	)
Other comprehensive income / (loss) before reclassifications		(1.6	)		1.0			4.8			4.2
Amounts reclassified from accumulated other comprehensive income / (loss)		1.4			2.6			3.8			7.8
Net current period other comprehensive income / (loss)		(0.2	)		3.6			8.6			12.0
Balance December 31, 2013	$	0.8		$	6.2		$	(33.7	)	$	(26.7	)

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Notes to Financial Statements

Note 4 – Regulatory Matters

In accordance with FASC 980, we have recognized total regulatory assets of $180.5 million and $203.8 million as of December 31, 2013 and 2012, respectively and total regulatory liabilities of $121.1 million and $117.4 million as of December 31, 2013 and 2012, respectively. 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.

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

Type of
Recovery^(a)

Amortization
Through

December 31,

2013

2012

$ in millions

Regulatory assets, current:

Transmission costs

2014

2.6

7.0

Fuel and purchased power recovery costs

2014

6.3

11.3

Energy efficiency program

2014

7.7

—

Other miscellaneous

2014

4.2

—

Total regulatory assets, current

20.8

18.3

Regulatory assets, non-current:

Deferred recoverable income taxes

B/C

Ongoing

32.4

35.1

Pension benefits

Ongoing

77.1

88.9

Unamortized loss on reacquired debt

Various

10.9

11.9

Deferred storm costs

Undetermined

25.6

24.4

CCEM smart grid and advanced metering infrastructure costs

6.6

6.6

Energy efficiency program costs

2014

—

5.2

Consumer education campaign

Undetermined

3.0

3.0

Retail settlement system costs

Undetermined

3.1

3.1

Other miscellaneous

Undetermined

1.0

7.3

Total regulatory assets, non-current

159.7

185.5

Regulatory liabilities, current:

Other miscellaneous

—

0.1

Total regulatory liabilities, current

—

0.1

Regulatory liabilities, non-current:

Estimated costs of removal—regulated property

115.0

112.1

Postretirement benefits

5.6

5.0

Other miscellaneous

0.5

0.2

Total regulatory liabilities, non-current

121.1

117.3

(a)

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

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

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

F – Recovery of incurred costs plus rate of return.

Regulatory Assets

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.

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Notes to Financial Statements

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. On June 12, 2013, we received a report from that external auditor recommending a pre-tax disallowance of $5.3 million of costs; a portion of which was recorded as a reserve against the regulatory asset. A hearing in this case was held on December 9, 2013 and we expect an order in the case in the second quarter of 2014.

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.

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 Other Comprehensive Income (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.

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.

Regional transmission organization costs represent costs incurred to join an RTO. The recovery of these costs will be requested in a future FERC rate case. In accordance with FERC precedence, we are amortizing these costs over a 10-year period that began in 2004 when we joined the PJM RTO. Due to the short-term nature of the remaining amortization period, the balance was reclassified to current regulatory assets in 2013 and is included in Other miscellaneous in the table above.

Deferred storm costs relate to costs incurred to repair the damage caused to DP&L’s transmission and distribution equipment by major storms in 2008, 2011 and 2012. DP&L filed an application with the PUCO in 2012 to recover these costs. There has been disagreement among DP&L, the PUCO staff and other intervenors in the case as to what portion of these storm costs should be recoverable. We continue to believe the costs we have deferred are probable for recovery based on established regulatory practices in the state of Ohio. A hearing is scheduled for this matter in March 2014. The outcome of this case is uncertain at this time.

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.

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.

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.

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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The Dayton Power and Light Company
Notes to Financial Statements

Other costs primarily include RPM capacity, other PJM and rate case costs and alternative energy costs that are or will be recovered over various periods.

Regulatory Liabilities

Fuel and purchased power recovery costs Please see “Regulatory Assets – Fuel and purchased power recovery 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 5 – Ownership of Coal-fired Facilities

DP&L and certain other Ohio utilities have undivided ownership interests in seven 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, 2013, DP&L had $24.0 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 Results 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, as well as the coal portion of our wholly-owned coal fired Hutchings Station at December 31, 2013, is as follows:

	DP&L Share				DP&L Investment
	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
Beckjord Unit 6		50.0		207	$	76	$	69	$	—	No
Conesville Unit 4		16.5		129		20		—		—	Yes
East Bend Station		31.0		186		—		—		—	Yes
Killen Station		67.0		402		622		303		4	Yes
Miami Fort Units 7 and 8		36.0		368		361		152		1	Yes
Stuart Station		35.0		808		744		307		16	Yes
Zimmer Station		28.1		365		1,098		657		3	Yes
Transmission (at varying percentages)						98		60		—
Total				2,465	$	3,019	$	1,548	$	24
Wholly-owned production unit
Hutchings Station		100.0		—	$	—	$	—	$	—	No

Currently, our coal-fired electric generation units at Hutchings and Beckjord do not have the SCR and FGD emission-control equipment installed. DP&L owns 100% of the Hutchings Station and has a 50% interest in

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Notes to Financial Statements

Beckjord Unit 6. On July 15, 2011, Duke Energy, a co-owner at the Beckjord Unit 6 facility, filed their Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord Station, including our commonly-owned Unit 6, in December 2014. This was followed by a notification by the joint owners of Beckjord Unit 6 to PJM, dated April 12, 2012, of a planned June 1, 2015 deactivation of this unit. We are depreciating Unit 6 through December 2014 and do not believe that any additional accruals or impairment charges are needed as a result of this decision.

As part of a settlement with the USEPA regarding Hutchings Station, DP&L signed an Administrative Consent Order and a Consent Agreement and Final Order (CAFO) that was filed on September 26, 2013. Together, these two agreements resolved the opacity and particulate emissions NOV at the Hutchings Station and required that all six coal-fired units at Hutchings cease operating on coal by September 30, 2013, and included an immaterial penalty and the completion of a Supplemental Environmental Project of $0.2 million within one year. The units were disabled for coal operations prior to September 30, 2013. We do not believe that any additional accruals are needed related to the Hutchings Station. These agreements do not affect Hutchings unit 7, a small combustion turbine.

As part of the provisional DPL purchase accounting adjustments related to the Merger, four stations (Beckjord, Conesville, East Bend and Hutchings) had future expected cash flows that, when discounted, produced a fair market value different than DP&L’s carrying value. Since DP&L did not apply push down accounting, this valuation did not affect the carrying value of these stations’ valuation at DP&L. In the fourth quarter of 2013, DP&L performed an impairment review of its stations and recorded an impairment of $86.0 million related to two of its stations, Conesville and East Bend. In the third quarter of 2012, DP&L performed an impairment review of its stations, and recorded an impairment of $80.8 million related to two of the stations, Conesville and Hutchings. See Note 15 for more information on these impairments.

Note 6 – Debt Obligations

Long-term debt is as follows:

Long-term debt

	December 31, 2013			December 31, 2012
$ in millions
First mortgage bonds due in September 2016 - 1.875%	$	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: 0.05% - 0.24% and 0.04% - 0.26%^(a)		100.0			—
U.S. Government note due in February 2061 - 4.2%		18.2			18.3
Capital lease obligations		—			0.1
Unamortized debt discount		(0.7	)		(0.1	)
Total long-term debt	$	876.9		$	332.7

(a)

- range of interest rates for the twelve months ended December 31, 2013 and December 31, 2012, respectively

Current portion - long-term debt

	December 31, 2013		December 31, 2012
$ in millions
First mortgage bonds due in October 2013 - 1.875%	$	—	$	470.0
Pollution control series due in November 2040 - variable rates: 0.05% - 0.24% and 0.04% - 0.26%^(a)		—		100.0
U.S. Government note due in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		0.1		0.3
Total current portion - long-term debt	$	0.2	$	570.4

(a)

- range of interest rates for the twelve months ended December 31, 2013 and December 31, 2012, respectively

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The Dayton Power and Light Company
Notes to Financial Statements

At December 31, 2013, maturities of long-term debt, including capital lease obligations, are summarized as follows:

Due within the twelve months ending December 31,
$ in millions
2014	$	0.2
2015		0.1
2016		445.1
2017		0.1
2018		0.1
Thereafter		432.2
		877.8
Unamortized discount		(0.7	)
Total long-term debt	$	877.1

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 two standby letters of credit issued by JPMorgan Chase Bank, N.A. DP&L amended these standby letters of credit on May 31, 2013 and extended the stated maturities to June 2018. These amended facilities are irrevocable, have no subjective acceleration clauses and remain subject to terms and conditions that are substantially similar to those of the pre-existing facilities. Fees associated with this letter of credit facility were not material during the years ended December 31, 2013, 2012 and 2011.

On April 20, 2010, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group. The agreement provided DP&L with the ability to increase the size of the facility by an additional $50.0 million. This agreement, originally for a three year term expiring on April 20, 2013, was extended through May 31, 2013 pursuant to an amendment dated April 11, 2013. DP&L had no outstanding borrowings under this credit facility at December 31, 2012 or at the termination of the agreement in May 2013. Fees associated with this revolving credit facility were not material during the years ended December 31, 2013, 2012 and 2011. This facility also contained a $50.0 million letter of credit sublimit. DP&L had no outstanding letters of credit against the facility at December 31, 2012 or at the termination of the agreement in May 2013.

On August 24, 2011, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group. This agreement was for a four year term expiring on August 24, 2015 and provided DP&L with the ability to increase the size of the facility by an additional $50.0 million. DP&L had no outstanding borrowings under this credit facility at December 31, 2012 or at the termination of the agreement in May 2013. Fees associated with this revolving credit facility were not material during the years ended December 31, 2013 and 2012 or the five months ended December 31, 2011. This facility also contains a $50.0 million letter of credit sublimit. DP&L had no outstanding letters of credit against the facility at December 31, 2012 or at the termination of the agreement in May 2013.

On May 10, 2013, DP&L terminated both of the unsecured revolving credit agreements mentioned above and concurrently closed a new $300.0 million unsecured revolving credit agreement with a syndicated bank group. This new $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. The other terms and conditions of this new revolving credit facility are substantially similar to those of the pre-existing DP&L revolving credit facilities. DP&L had no outstanding borrowings under this facility at December 31, 2013. At December 31, 2013, there was a letter of credit in the amount of $0.4 million outstanding, with the remaining $299.6 million available to DP&L. Fees associated with this revolving credit facility were not material during the year ended December 31, 2013.

DP&L’s prior unsecured revolving credit agreements and DP&L’s standby letters of credit had one financial covenant which measured 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

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The Dayton Power and Light Company
Notes to Financial Statements

the quarter. DP&L’s new unsecured revolving credit agreement and DP&L’s amended standby letters of credit maintain the Total Debt to Total Capitalization financial covenant and add the EBITDA to Interest Expense ratio as a second financial covenant. 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.

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. On October 1, 2013, DP&L used the net proceeds of these new bonds, along with cash on hand, to redeem, at par value, the $470.0 million of first mortgage bonds that matured on October 1, 2013.

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

Note 7 – Income Taxes

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

	Year ended December 31, 2013			Year ended December 31, 2012			Year ended December 31, 2011
$ in millions
Computation of tax expense
Federal income tax expense / (benefit)^(a)	$	35.5		$	50.9		$	103.8
Increases (decreases) in tax resulting from:
State income taxes, net of federal effect		0.3			(2.0	)		1.4
Depreciation of AFUDC - Equity		(2.5	)		3.0			(3.2	)
Investment tax credit amortized		(2.5	)		(2.5	)		(2.5	)
Section 199 - domestic production deduction		(4.1	)		(2.5	)		(4.9	)
Non-deductible merger-related compensation		—			0.6			3.6
Accrual (settlement) for open tax years		(8.8	)		—			—
ESOP		—			—			13.6
Compensation and benefits		—			—			(5.3	)
Other, net^(b)		0.7			7.6			(2.3	)
Total tax expense	$	18.6		$	55.1		$	104.2
Components of Tax Expense
Federal - current	$	38.6		$	52.1		$	54.9
State and Local - current		(0.1	)		1.0			0.9
Total current		38.5			53.1			55.8
Federal - deferred		(20.4	)		4.7			47.1
State and local - deferred		0.5			(2.7	)		1.3
Total deferred		(19.9	)		2.0			48.4
Total tax expense	$	18.6		$	55.1		$	104.2

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The Dayton Power and Light Company
Notes to Financial Statements

	December 31,
	2013			2012
$ in millions
Net non-current Assets / (Liabilities)
Depreciation / property basis	$	(607.1	)	$	(622.1	)
Income taxes recoverable		(11.4	)		(12.3	)
Regulatory assets		(15.6	)		(20.6	)
Investment tax credit		8.8			9.6
Compensation and employee benefits		(0.2	)		0.3
Other		(6.8	)		(6.9	)
Net non-current liabilities	$	(632.3	)	$	(652.0	)
Net current Assets / (Liabilities)^(c)
Other	$	(5.0	)	$	2.0
Net current assets / (liabilities)	$	(5.0	)	$	2.0

(a)

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

(b)

Includes expense of $1.1 million, $7.6 million and benefit of $2.4 million in the years ended December 31, 2013, 2012 and 2011, respectively, of income tax related to adjustments from prior years.

(c)

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

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

	Year ended December 31, 2013		Year ended December 31, 2012			Year ended December 31, 2011
$ in millions
Tax expense / (benefit)	$	7.0	$	(0.8	)	$	(7.2	)

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 for DP&L is as follows:

$ in millions
Balance at December 31, 2011	$	25.0
Calendar 2012
Tax positions taken during prior period		(6.3	)
Tax positions taken during current period		(0.4	)
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

Of the December 31, 2013 balance of unrecognized tax benefits, $8.8 million is due to uncertainty in the timing of deductibility.

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The Dayton Power and Light Company
Notes to Financial Statements

We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The following table represents the amounts accrued as well as the expense / (benefit) recorded as of and for the periods noted below:

Amounts in Balance Sheet	Year ended December 31, 2013		Year ended December 31, 2012		Year ended December 31, 2011
$ in millions
Liability	$	0.2	$	0.8	$	0.9

Amounts in Statement of Operations	Year ended December 31, 2013			Year ended December 31, 2012			Year ended December 31, 2011
$ in millions
Expense / (benefit)	$	(0.6	)	$	(0.1	)	$	0.6

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. Effective December 22, 2013, certain employees of DP&L became employees of the Service Company of the US SBU. 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 was replaced by the DPL Inc. Supplemental Executive Defined Contribution Retirement Plan (SEDCRP) effective January 1, 2006, which is for certain active and former key executives. Pursuant to the SEDCRP, we provided a supplemental retirement benefit to participants by crediting an account established for each participant in accordance with the Plan requirements. We designated as hypothetical investment funds under the SEDCRP one or more of the investment funds provided under The Dayton Power and Light Company Employee Savings Plan. Each participant could change his or her hypothetical investment fund selection at specified times. If a participant did not elect a

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The Dayton Power and Light Company
Notes to Financial Statements

hypothetical investment fund(s), then we selected the hypothetical investment fund(s) for such participant. Per the SEDCRP plan document, the balances in the SEDCRP, including earnings on contributions, were paid out to participants in December 2011, following the merger with AES on November 28, 2011. However, the SEDCRP continued and 2012 and 2011 contributions were calculated and paid in March 2013 and 2012, respectively. The SEDCRP was terminated by the Board of Directors as of December 31, 2012. We also have an immaterial unfunded liability related to agreements for retirement benefits of certain terminated and retired key executives.

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, 2013 and 2012. DP&L made a discretionary contribution of $40.0 million during the year ended December 31, 2011.

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.

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, 2013 and 2012. 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.

	Pension
	Years ended December 31,
	2013			2012
$ in millions
Change in benefit obligation
Benefit obligation at beginning of period	$	395.6		$	365.2
Service cost		7.2			6.2
Interest cost		15.6			17.3
Plan amendments		—			—
Actuarial (gain) / loss		(26.5	)		29.1
Benefits paid		(21.4	)		(22.2	)
Benefit obligation at end of period		370.5			395.6

Change in plan assets
Fair value of plan assets at beginning of period		361.4			335.9
Actual return on plan assets		8.7			46.2
Contributions to plan assets		0.4			1.5
Benefits paid		(21.4	)		(22.2	)
Fair value of plan assets at end of period		349.1			361.4
Funded status of plan	$	(21.4	)	$	(34.2	)

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The Dayton Power and Light Company
Notes to Financial Statements

	Postretirement
	Years ended December 31,
	2013			2012
$ in millions
Change in benefit obligation
Benefit obligation at beginning of period	$	22.4		$	21.7
Service cost		0.2			0.1
Interest cost		0.8			0.9
Actuarial (gain) / loss		(2.2	)		1.2
Benefits paid		(1.5	)		(1.7	)
Medicare Part D reimbursement		—			0.2
Benefit obligation at end of period		19.7			22.4
Change in plan assets
Fair value of plan assets at beginning of period		4.2			4.5
Actual return on plan assets		—			0.2
Contributions to plan assets		1.0			1.2
Benefits paid		(1.5	)		(1.7	)
Fair value of plan assets at end of period		3.7			4.2
Funded status of plan	$	(16.0	)	$	(18.2	)

	Pension						Postretirement
	December 31,						December 31,
	2013			2012			2013			2012
$ in millions
Amounts recognized in the Balance sheets
Current liabilities	$	(0.4	)	$	(0.4	)	$	(0.5	)	$	(0.6	)
Non-current liabilities		(21.0	)		(33.8	)		(15.5	)		(17.6	)
Net liability at Year ended December 31,	$	(21.4	)	$	(34.2	)	$	(16.0	)	$	(18.2	)
Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
Components:
Prior service cost	$	16.3		$	19.0		$	0.7		$	0.8
Net actuarial loss / (gain)		115.1			136.1			(6.9	)		(5.7	)
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax	$	131.4		$	155.1		$	(6.2	)	$	(4.9	)
Recorded as:
Regulatory asset	$	76.3		$	88.0		$	—		$	0.5
Regulatory liability		—			—			(5.2	)		(5.0	)
Accumulated other comprehensive income		55.1			67.1			(1.0	)		(0.4	)
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax	$	131.4		$	155.1		$	(6.2	)	$	(4.9	)

The accumulated benefit obligation for our defined benefit pension plans was $359.8 million and $382.5 million at December 31, 2013 and 2012, respectively.

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The Dayton Power and Light Company
Notes to Financial Statements

The net periodic benefit cost (income) of the pension and postemployment benefit plans were:

Net Periodic Benefit Cost - Pension

	Years ended December 31,
	2013			2012			2011
$ in millions
Service cost	$	7.2		$	6.2		$	5.0
Interest cost		15.6			17.3			17.0
Expected return on assets^(a)		(23.6	)		(22.7	)		(24.5	)
Amortization of unrecognized:
Actuarial gain		9.3			8.8			8.0
Prior service cost		2.8			2.8			2.1
Net periodic benefit cost before adjustments		11.3			12.4			7.6
Settlement Expense		—			0.6			—
Net periodic benefit cost after adjustments	$	11.3		$	13.0		$	7.6

(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 $351.2 million in 2013, $346.0 million in 2012, and $335.0 million in 2011.

Net Periodic Benefit Cost / (Income) - Postretirement

	Years ended December 31,
	2013			2012			2011
$ in millions
Service cost	$	0.2		$	0.1		$	0.1
Interest cost		0.8			0.9			1.0
Expected return on assets		(0.2	)		(0.3	)		(0.3	)
Amortization of unrecognized:
Actuarial loss		(0.7	)		(0.9	)		(1.1	)
Prior service credit		0.1			0.1			0.1
Net periodic benefit cost / (income) before adjustments	$	0.2		$	(0.1	)	$	(0.2	)

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The Dayton Power and Light Company
Notes to Financial Statements

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

Pension

	Years ended December 31,
	2013			2012			2011
$ in millions
Net actuarial loss / (gain)	$	(11.7	)	$	5.2		$	22.8
Prior service cost		—			—			7.1
Reversal of amortization item:
Net actuarial loss		(9.3	)		(9.4	)		(8.0	)
Prior service cost		(2.8	)		(2.8	)		(2.0	)
Transition asset		—			—			—
Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	(23.8	)	$	(7.0	)	$	19.9
Total recognized in net periodic benefit cost Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	(12.5	)	$	6.0		$	27.5

Postretirement

	Years ended December 31,
	2013			2012			2011
$ in millions
Net actuarial loss / (gain)	$	(1.9	)	$	1.1		$	(1.3	)
Prior service credit		—			—			—
Reversal of amortization item:
Net actuarial gain		0.7			0.9			1.2
Prior service credit		(0.1	)		(0.1	)		(0.1	)
Transition asset		—			—			—
Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	(1.3	)	$	1.9		$	(0.2	)
Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities	$	(1.1	)	$	1.8		$	(0.4	)

Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2014 are:

	Pension		Postretirement
$ in millions
Net actuarial gain / (loss)	$	6.4	$	(0.8	)
Prior service cost	$	2.8	$	0.1

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.

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The Dayton Power and Light Company
Notes to Financial Statements

For 2014, we are decreasing our expected long-term rate of return assumption from 7.00% to 6.75% for pension plan assets and we are maintaining 6.00% for postemployment benefit plan assets. These rates of return represent our long-term assumptions based on our current portfolio mixes. Also, for 2014, we have increased our assumed discount rate to 4.86% from 4.04% for pension and to 4.58% from 3.75% 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 2014 pension expense of approximately $3.4 million. A 25 basis point change in the discount rate for pension would result in an increase or decrease of approximately $0.3 million to 2014 pension expense.

Our overall discount rate was evaluated in relation to the Aon AA Above Median Yield Curve which represents a portfolio of Above Median AA-rated bonds used to settle pension obligations. Peer data and historical returns were also reviewed to verify the reasonableness and appropriateness of our discount rate used in the calculation of benefit obligations and expense.

The weighted average assumptions used to determine benefit obligations during the years ended December 31, 2013, 2012 and 2011 were:

Benefit Obligation Assumptions	Pension									Postretirement
	2013			2012			2011			2013			2012			2011
Discount rate for obligations		4.86	%		4.04	%		4.88	%		4.58	%		3.75	%		4.62	%
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, 2013, 2012 and 2011 were:

Net Periodic Benefit Cost / (Income) Assumptions	Pension									Postretirement
	2013			2012			2011			2013			2012			2011
Discount rate		4.04	%		4.88	%		5.31	%		4.58	%		4.62	%		4.96	%
Expected rate of return on plan assets		6.75	%		7.00	%		8.00	%		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, 2013, 2012 and 2011 are as follows:

Health Care Cost Assumptions	Expense									Benefit Obligation
	2013			2012			2011			2013			2012			2011
Pre - age 65
Current health care cost trend rate		8.00	%		8.50	%		8.50	%		7.75	%		8.00	%		8.50	%
Year trend reaches ultimate		2019			2019			2018			2023			2019			2019
Post - age 65
Current health care cost trend rate		7.50	%		8.00	%		8.00	%		6.75	%		7.50	%		8.00	%
Year trend reaches ultimate		2018			2018			2017			2021			2018			2018
Ultimate health care cost trend rate		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%

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The Dayton Power and Light Company
Notes to Financial Statements

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

	One-percent increase		One-percent decrease
$ in millions
Service cost plus interest cost	$	0.1	$	(0.1	)
Benefit obligation	$	0.9	$	(0.8	)

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

Estimated future benefit payments and Medicare Part D reimbursements

	Pension		Postretirement
$ in millions due within the following years:
2014	$	25.0	$	2.2
2015	$	23.9	$	2.1
2016	$	23.9	$	2.0
2017	$	24.3	$	1.8
2018	$	24.6	$	1.6
2019 - 2023	$	126.5	$	6.7

We expect to make contributions of $0.4 million to our SERP in 2014 to cover benefit payments. We also expect to contribute $1.9 million to our other postemployment benefit plans in 2014 to cover benefit payments.

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 2013 plan year, the funded status of our defined benefit pension plan as calculated under the requirements of the Act was 113.96% and is estimated to be 113.96% until the 2014 status is certified in September 2014 for the 2014 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 30 - 80% for equity securities, 30 - 65% for fixed income securities, 0 – 10% for cash, and 0 - 25% for alternative investments. Equity

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The Dayton Power and Light Company
Notes to Financial Statements

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 types of investments include hedge funds that follow several different strategies.

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

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)

$ in millions

Equity securities^(a)

Small/Mid cap equity

10.5

—

Large cap equity

20.8

—

International equity

20.3

—

Emerging markets equity

3.2

—

SIIT dynamic equity

10.5

—

Total equity securities

65.3

—

Debt Securities^(b)

Emerging markets debt

6.6

—

High yield bond

6.9

—

Long duration fund

223.3

—

Total debt securities

236.8

—

Cash and cash equivalents^(c)

Cash

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. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the funds.

(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. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(c)

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

(d)

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

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The Dayton Power and Light Company
Notes to Financial Statements

The fair values of our pension plan assets at December 31, 2012 by asset category are as follows:

Fair Value Measurements for Pension Plan Assets at December 31, 2012
Asset Category	Market Value at December 31, 2012		Quoted prices in active markets for identical assets		Significant observable inputs		Significant unobservable inputs
			(Level 1)		(Level 2)		(Level 3)
$ in millions
Equity securities^(a)
Small/Mid cap equity	$	14.3	$	14.3	$	—	$	—
Large cap equity		50.5		50.5		—		—
International equity		37.0		37.0		—		—
Total equity securities		101.8		101.8		—		—
Debt Securities^(b)
Emerging markets debt		7.4		7.4		—		—
High yield bond		12.7		12.7		—		—
Long duration fund		188.6		188.6		—		—
Total debt securities		208.7		208.7		—		—
Cash and cash equivalents^(c)
Cash		13.9		13.9		—		—
Other investments^(d)
Limited partnership interest		—		—		—		—
Common collective fund		37.0		—		37.0		—
Total other investments		37.0		—		37.0		—

Total pension plan assets	$	361.4	$	324.4	$	37.0	$	—

(a)

(b)

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

(c)

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

(d)

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

This disclosure reflects changes in the 2012 presentation for $310.5 million of equity and debt mutual funds that were previously presented as Level 2 fair value measurements which have been reclassified as Level 1 fair value measurements. In addition, this disclosure reflects changes in the 2012 presentation for $37.0 million of alternative investment funds that were previously presented as Level 3 fair value measurements which have been reclassified as Level 2 fair value measurements. This change in presentation does not impact the fair value of the securities or the financial statements for the year ended December 31, 2012.

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The Dayton Power and Light Company
Notes to Financial Statements

The fair values of our other postemployment benefit 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

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)

$ in millions

JP Morgan Core Bond Fund^(a)

3.7

—

(a)

This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

The fair values of our other postemployment benefit plan assets at December 31, 2012 by asset category are as follows:

Fair Value Measurements for Pension Plan Assets at December 31, 2012
Asset Category	Market Value at December 31, 2012		Quoted prices in active markets for identical assets		Significant observable inputs		Significant unobservable inputs
			(Level 1)		(Level 2)		(Level 3)
$ in millions
JP Morgan Core Bond Fund^(a)	$	4.2	$	4.2	$	—	$	—

(a)

This disclosure reflects changes in the 2012 presentation for $4.2 million of debt mutual funds that were previously presented as Level 2 fair value measurements which have been reclassified as Level 1 fair value measurements. This change in presentation does not impact the fair value of the securities or the financial statements for the year ended December 31, 2012.

During October 1992, our Board of Directors approved the formation of a Company-sponsored ESOP to fund matching contributions to DP&L’s 401(k) retirement savings plan and certain other payments to eligible full-time employees. ESOP shares that were used to fund matching contributions to DP&L’s 401(k) vested after either two or three years of service in accordance with the match formula effective for the respective plan match year; other compensation shares awarded vested immediately. In 1992, the ESOP Plan entered into a $90 million loan agreement with DPL in order to purchase shares of DPL common stock in the open market. The leveraged ESOP was funded by an exempt loan, which was secured by the ESOP shares. As debt service payments were made on the loan, shares were released on a pro rata basis. The term loan agreement provided for principal and interest on the loan to be paid prior to October 9, 2007, with the right to extend the loan for an additional ten years. In 2007, the maturity date was extended to October 7, 2017. Effective January 1, 2009, the interest on the loan was amended to a fixed rate of 2.06%, payable annually. Dividends received by the ESOP were used to repay the principal and interest on the ESOP loan to DPL. Dividends on the allocated shares were charged to retained earnings and the share value of these dividends was allocated to participants.

During December 2011, the ESOP Plan was terminated and participant balances were transferred to one of the two DP&L sponsored defined contribution 401(k) plans. On December 5, 2011, the ESOP Trust paid the total outstanding principal and interest of $68 million on the loan with DPL, using the merger proceeds from DPL common stock held within the ESOP suspense account.

Compensation expense recorded, based on the fair value of the shares committed to be released, amounted to $4.8 million in the year ended December 31, 2011.

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The Dayton Power and Light Company
Notes to Financial Statements

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, 2013 and 2012. See also Note 10 for the fair values of our derivative instruments.

	December 31, 2013				December 31, 2012
	Cost		Fair Value		Cost		Fair Value
$ in millions
Assets
Money market funds	$	0.3	$	0.3	$	0.2	$	0.2
Equity securities		3.3		4.4		4.0		5.1
Debt securities		5.4		5.5		4.6		5.0
Hedge Funds		0.9		0.9		—		—
Real Estate		0.4		0.4		0.3		0.3
Total assets	$	10.3	$	11.5	$	9.1	$	10.6
Liabilities
Debt	$	877.9	$	859.6	$	903.1	$	926.9

Debt

The fair value of debt is based on current public market prices for disclosure purposes only. Unrealized gains or losses are not recognized in the financial statements as debt is presented at amortized cost in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2013 to 2061.

Master Trust Assets

DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans 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 assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.

DP&L had $1.2 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2013 and $1.6 million ($1 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2012.

Various investments were sold during the past twelve months to facilitate the distribution of benefits. During the past twelve months, $2.1 million ($1.4 million after tax) of unrealized gains were reversed into earnings. Over the next twelve months, $0.1 million ($0.1 million after tax) of unrealized gains are expected to be reversed to earnings.

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The Dayton Power and Light Company
Notes to Financial Statements

Net Asset Value (NAV) per Unit

The following tables disclose the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of December 31, 2013 and 2012. These assets are part of the Master Trust. Fair values estimated using the NAV per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV per unit on the reporting date. Investments that have restrictions on the redemption of the investments are Level 3 inputs. As of December 31, 2013, DP&L did not have any investments for sale at a price different from the NAV per unit.

Fair Value Estimated Using Net Asset Value per Unit
	Fair Value at December 31, 2013		Unfunded Commitments		Redemption Frequency
$ in millions
Money market fund^(a)	$	0.3	$	—		Immediate
Equity securities^(b)		4.4		—		Immediate
Debt Securities^(c)		5.5		—		Immediate
Hedge Funds^(d)		0.9		—		Quarterly
Real Estate^(e)		0.4		—		Quarterly
Total	$	11.5	$	—

(a)

This category includes investments in high-quality, short-term securities. Investments in this category can be redeemed immediately at the current NAV.

(b)

This category includes investments in hedge funds representing an S&P 500 Index and the Morgan Stanley Capital International U.S. Small Cap 1750 Index. Investments in this category can be redeemed immediately at the current NAV per unit.

(c)

This category includes investments in U.S. Treasury obligations and U.S. investment grade bonds. Investments in this category can be redeemed immediately at the current NAV per unit.

(d)

This category includes hedge funds investing in fixed income securities and currencies, short and long-term equity investments, and a diversified fund with investments in bonds, stocks, real estate and commodities.

(e)

This category includes EFT real estate funds that invest in U.S. and International properties.

Fair Value Estimated Using Net Asset Value per Unit
	Fair Value at December 31, 2012		Unfunded Commitments		Redemption Frequency
$ in millions
Money market fund^(a)	$	0.2	$	—		Immediate
Equity securities^(b)		5.1		—		Immediate
Debt Securities^(c)		5.0		—		Immediate
Multi-strategy fund^(d)		0.3		—		Immediate
Total	$	10.6	$	—

(a)

This category includes investments in high-quality, short-term securities. Investments in this category can be redeemed immediately at the current net asset value per unit.

(b)

This category includes investments in hedge funds representing an S&P 500 index and the Morgan Stanley Capital International (MSCI) U.S. Small Cap 1750 Index. Investments in this category can be redeemed immediately at the current net asset value per unit.

(c)

This category includes investments in U.S. Treasury obligations and U.S. investment grade bonds. Investments in this category can be redeemed immediately at the current net asset value per unit.

(d)

This category includes a mix of actively managed funds holding investments in stocks, bonds and short-term investments in a mix of actively managed funds. Investments in this category can be redeemed immediately at the current net asset value per unit.

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Notes to Financial Statements

Fair Value Hierarchy

•

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

•

Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not 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, 2013 and 2012.

The fair value of assets and liabilities at December 31, 2013 and 2012 measured on a recurring basis and the respective category within the fair value hierarchy for DP&L was determined as follows:

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Level 1

Level 2

Level 3

Fair Value at
December 31,
2013^(a)

Based on
Quoted Prices
in
Active
Markets

Other
observable
inputs

Unobservable
inputs

$ in millions

Assets

Master trust assets

Money market funds

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

0.3

11.2

—

Derivative assets

Heating oil futures

0.2

—

FTRs

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

0.5

24.6

0.2

Liabilities

Derivative liabilities

Forward power contracts

10.6

—

10.6

—

Total derivative liabilities

10.6

—

10.6

—

Long Term Debt

859.6

—

841.1

18.5

Total liabilities

870.2

—

851.7

18.5

(a)

Includes credit valuation adjustment.

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Notes to Financial Statements

Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
	Fair Value at December 31, 2012^(a)		Based on Quoted Prices in Active Markets		Other observable inputs		Unobservable inputs
$ in millions
Assets
Master trust assets
Money market funds	$	0.2	$	0.2	$	—	$	—
Equity securities		5.1		—		5.1		—
Debt securities		5.0		—		5.0		—
Multi-strategy fund		0.3		—		0.3		—
Total Master trust assets		10.6		0.2		10.4		—
Derivative assets
Heating oil futures		0.2		0.2		—		—
Forward power contracts		7.3		—		7.3		—
Total derivative assets		7.5		0.2		7.3		—
Total assets	$	18.1	$	0.4	$	17.7	$	—
Liabilities
Derivative liabilities
Forward NYMEX coal contracts	$	0.1	$	—	$	—	$	0.1
Forward power contracts		11.6		—		11.6		—
Total derivative liabilities		11.7		—		11.6		0.1
Long Term debt		926.9		—		908.0		18.9
Total liabilities	$	938.6	$	—	$	919.6	$	19.0

(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. Our long-term leases and the WPAFB note are not publicly traded. Fair value is assumed to equal carrying value. These fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures were not presented since debt is not recorded at fair value.

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The Dayton Power and Light Company
Notes to Financial Statements

Approximately 95% of the inputs to the fair value of our derivative instruments are from quoted market prices for DP&L.

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. An ARO liability in the amount of $0.1 million was established in 2012 associated with a gypsum landfill disposal site that is presently under construction. This increase in 2012 was offset by a $0.1 million reduction in ARO for asbestos as a result of an acceleration of removal and remediation activities. 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:

Year ended December 31, 2013

Carrying
Amount

Fair Value

Gross
Loss

Level 1

Level 2

Level 3

$ in millions

Assets

Long-lived assets held and used^(a)

Conesville

30.0

—

20.0

10.0

East Bend

76.0

—

76.0

	Year ended December 31, 2012
	Carrying Amount		Fair Value						Gross Loss
	Carrying Amount		Level 1		Level 2		Level 3		Gross Loss
$ in millions
Assets
Long-lived assets held and used^(a)
Conesville	$	97.5	$	—	$	—	$	25.0	$	72.5
Hutchings	$	8.3	$	—	$	—	$	—	$	8.3

(a)

See Note 15 for further information.

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The Dayton Power and Light Company
Notes to Financial Statements

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

Fair
Value

Valuation Technique

Unobservable input

Range (Weighted
Average)

$ in millions

Long-lived assets held and used:

Conesville

20.0

Discounted cash flows

Annual revenue
growth

-31% to 18% (0%)

Annual pretax
operating margin

-9% to 18% (10%)

East Bend

—

Discounted cash flows

Annual revenue
growth

-15% to 22% (4%)

Annual pretax
operating margin

-3% to 34% (15%)

Note 10 – Derivative Instruments and Hedging Activities

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

At December 31, 2013, DP&L 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

3,172.4

(2,888.5

)

283.9

At December 31, 2012, DP&L 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		6.9		—			6.9
Heating Oil Futures	Mark to Market		Gallons		1,764.0		—			1,764.0
Forward Power Contracts	Cash Flow Hedge		MWh		1,021.0		(2,197.9	)		(1,176.9	)
Forward Power Contracts	Mark to Market		MWh		2,296.6		(4,760.4	)		(2,463.8	)

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The Dayton Power and Light Company
Notes to Financial Statements

Cash Flow Hedges

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

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

The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges:

	Year ended December 31, 2013						Year ended December 31, 2012						Year ended December 31, 2011
	Power			Interest Rate Hedge			Power			Interest Rate Hedge			Power			Interest Rate Hedge
$ in millions (net of tax)
Beginning accumulated derivative gain / (loss) in AOCI^(a)	$	(4.7	)	$	7.3		$	(0.8	)	$	9.8		$	(1.8	)	$	12.2
Net gains / (losses) associated with current period hedging transactions		1.0			—			(3.0	)		—			(1.2	)		—

Net gains reclassified to earnings:
Interest Expense		—			(2.1	)		—			(2.5	)		—			(2.4	)
Revenues		1.4			—			(1.1	)		—			1.2			—
Purchased Power		3.3			—			0.2			—			1.0			—
Ending accumulated derivative gain / (loss) in AOCI	$	1.0		$	5.2		$	(4.7	)	$	7.3		$	(0.8	)	$	9.8
Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the years ended December 31, 2013, 2012 and 2011.
Portion expected to be reclassified to earnings in the next twelve months^(a)	$	(2.2	)	$	(1.1	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		36			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

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The Dayton Power and Light Company
Notes to Financial Statements

operations in the period in which the change occurred. This is commonly referred to as “MTM accounting.” Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We mark to market FTRs, heating oil futures, forward NYMEX-quality coal contracts 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 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 statements of results of operations or balance sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the years ended December 31, 2013, 2012 and 2011.

Year ended December 31, 2013

NYMEX
Coal

Heating Oil

FTRs

Power

Total

$ in millions

Derivatives not designated as hedging instruments

Change in unrealized gain / (loss)

—

0.3

(1.2

)

(0.9

)

Realized gain

—

0.1

1.2

1.6

2.9

Total

—

0.1

1.5

0.4

2.0

Recorded on Balance Sheet:

Partners' share of loss

—

Regulatory asset

—

Recorded in Income Statement: gain / (loss)

Revenue

—

0.2

Purchased Power

—

1.5

0.2

1.7

Fuel

—

0.1

—

0.1

O&M

—

Total

—

0.1

1.5

0.4

2.0

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The Dayton Power and Light Company
Notes to Financial Statements

Year ended December 31, 2012
	NYMEX Coal			Heating Oil			FTRs			Power		Total
$ in millions
Derivatives not designated as hedging instruments
Change in unrealized gain / (loss)	$	14.5		$	(1.6	)	$	(0.2	)	$	3.0	$	15.7
Realized gain / (loss)		(29.5	)		1.9			0.5			4.9		(22.2	)
Total	$	(15.0	)	$	0.3		$	0.3		$	7.9	$	(6.5	)
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		—			—			—			2.7		2.7
Purchased Power		—			—			0.3			5.2		5.5
Fuel		(20.2	)		0.7			—			—		(19.5	)
O&M		—			0.2			—			—		0.2
Total	$	(15.0	)	$	0.3		$	0.3		$	7.9	$	(6.5	)

Year ended December 31, 2011
	NYMEX Coal			Heating Oil		FTRs			Power			Total
$ in millions
Derivatives not designated as hedging instruments
Change in unrealized gain / (loss)	$	(52.1	)	$	0.1	$	(0.1	)	$	0.3		$	(51.8	)
Realized gain / (loss)		7.5			2.3		(0.6	)		(1.4	)		7.8
Total	$	(44.6	)	$	2.4	$	(0.7	)	$	(1.1	)	$	(44.0	)
Recorded on Balance Sheet:
Partners' share of loss	$	(26.1	)	$	—	$	—		$	—		$	(26.1	)
Regulatory asset		(7.1	)		—		—			—			(7.1	)
Recorded in Income Statement: gain / (loss)
Revenue		—			—		—			2.5			2.5
Purchased Power		—			—		(0.7	)		(3.6	)		(4.3	)
Fuel		(11.4	)		2.2		—			—			(9.2	)
O&M		—			0.2		—			—			0.2
Total	$	(44.6	)	$	2.4	$	(0.7	)	$	(1.1	)	$	(44.0	)

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The Dayton Power and Light Company
Notes to Financial Statements

The following tables show the fair value and balance sheet classification of DP&L’s derivative instruments at December 31, 2013 and 2012.

Fair Values of Derivative Instruments
December 31, 2013

Gross Amounts Not Offset
in the Balance Sheets

Hedging
Designation

Gross Fair
Value as
presented in
the Balance
Sheets

Financial
Instruments
with Same
Counterparty
in Offsetting
Position

Cash
Collateral

Net Amount

$ in millions

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

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The Dayton Power and Light Company
Notes to Financial Statements

Fair Values of Derivative Instruments December 31, 2012
				Gross Amounts Not Offset in the Balance Sheets
	Hedging Designation	Gross Fair Value as presented in the Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Amount
$ in millions
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.5	$	(0.5	)	$	—		$	—
Forward power contracts	MTM		2.8		(1.5	)		—			1.3
Heating oil futures	MTM		0.2		—			(0.2	)		—

Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		0.5		(0.5	)		—			—
Forward power contracts	MTM		3.6		(0.6	)		—			3.0
Total assets		$	7.6	$	(3.1	)	$	(0.2	)	$	4.3

Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	6.7	$	(0.5	)	$	(2.1	)	$	4.1
FTRs	MTM		0.1		—			—			0.1
Forward power contracts	MTM		2.7		(1.5	)		(0.5	)		0.7

Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		1.5		(0.5	)		(0.9	)		0.1
Forward power contracts	MTM		0.7		(0.6	)		—			0.1
Total liabilities		$	11.7	$	(3.1	)	$	(3.5	)	$	5.1

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 DP&L’s derivative instruments that are in a MTM loss position at December 31, 2013 is $10.6 million. This amount is offset by $5.6 million in a broker margin account and with other counterparties 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 $4.7 million. If DP&L debt were to fall below investment grade, DP&L could be required to post collateral for the remaining $0.3 million.

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The Dayton Power and Light Company
Notes to Financial Statements

Note 11 – Share-based Compensation

In April 2006, DPL’s shareholders approved The DPL Inc. Equity and Performance Incentive Plan (the EPIP) which became immediately effective for a term of ten years. The Compensation Committee of the Board of Directors designated the employees and directors eligible to participate in the EPIP and the times and types of awards to be granted. A total of 4,500,000 shares of DPL common stock had been reserved for issuance under the EPIP. The EPIP also covered certain employees of DP&L.

As a result of the Merger, discussed in Note 2, vesting of all share-based awards was accelerated as of the Merger date. The remaining compensation expense of $5.5 million ($3.6 million after tax) was expensed as of the Merger date.

The following table summarizes share-based compensation expense (note that there is no share-based compensation activity after November 27, 2011 as a result of the Merger):

	Year ended December 31, 2011
$ in millions
Restricted stock units	$	—
Performance shares		2.4
Restricted shares		5.3
Non-employee directors' RSUs^(a)		0.6
Management performance shares		1.8
Share-based compensation included in Operation and maintenance expense		10.1
Income tax benefit		(3.5	)
Total share-based compensation, net of tax	$	6.6

(a)

Includes an amount associated with compensation awarded to DPL’s Board of Directors which is immaterial in total.

Share-based awards issued in DPL’s common stock were distributed from treasury stock prior to the Merger; as of the Merger date, remaining share-based awards were distributed in cash in accordance with the Merger agreement.

Determining Fair Value

Valuation and Amortization Method – We estimated the fair value of performance shares using a Monte Carlo simulation; restricted shares were valued at the closing market price on the day of grant and the Directors’ RSUs were valued at the closing market price on the day prior to the grant date. We amortized the fair value of all awards on a straight-line basis over the requisite service periods, which are generally the vesting periods.

Expected Volatility – Our expected volatility assumptions were based on the historical volatility of DPL common stock. The volatility range captured the high and low volatility values for each award granted based on its specific terms.

Expected Life – The expected life assumption represented the estimated period of time from the grant date until the exercise date and reflected historical employee exercise patterns.

Risk-Free Interest Rate – The risk-free interest rate for the expected term of the award was based on the corresponding yield curve in effect at the time of the valuation for U.S. Treasury bonds having the same term as the expected life of the award, i.e., a five-year bond rate was used for valuing an award with a five year expected life.

Expected Dividend Yield – The expected dividend yield was based on DPL’s current dividend rate, adjusted as necessary to capture anticipated dividend changes and the 12 month average DPL common stock price.

Expected Forfeitures – The forfeiture rate used to calculate compensation expense was based on DPL’s historical experience, adjusted as necessary to reflect special circumstances.

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Notes to Financial Statements

Stock Options

In 2000, DPL’s Board of Directors adopted and DPL’s shareholders approved The DPL Inc. Stock Option Plan. With the approval of the EPIP in April 2006, no new awards were granted under The DPL Inc. Stock Option Plan. Prior to the Merger, all outstanding stock options had been exercised or had expired.

Summarized stock option activity was as follows (note that there is no stock option activity after November 27, 2011 as a result of the Merger):

	Year ended December 31, 2011
Options:
Outstanding at beginning of period		351,500
Granted		—
Exercised		(75,500	)
Expired		(276,000	)
Forfeited		—
Outstanding at end of period		—
Exercisable at end of period		—

Weighted average option prices per share:
Outstanding at beginning of period	$	28.04
Granted	$	—
Exercised	$	21.02
Expired	$	29.42
Forfeited	$	—
Outstanding at end of period	$	—
Exercisable at end of period	$	—

The following table reflects information about stock option activity during the period (note that there is no stock option activity after November 27, 2011 as a result of the Merger):

	Year ended December 31, 2011
$ in millions
Weighted-average grant date fair value of options granted during the period	$	—
Intrinsic value of options exercised during the period	$	0.7
Proceeds from options exercised during the period	$	1.6
Excess tax benefit from proceeds of options exercised	$	0.2
Fair value of options that vested during the period	$	—
Unrecognized compensation expense	$	—
Weighted-average period to recognize compensation expense (in years)		—

Performance Shares

Under the EPIP, the Board of Directors adopted a Long-Term Incentive Plan (LTIP) under which DPL granted a targeted number of performance shares of common stock to executives. Grants under the LTIP were awarded based on a Total Shareholder Return Relative to Peers performance. The Total Shareholder Return Relative to Peers is considered a market condition in accordance with the accounting guidance for share-based compensation.

At the Merger date, vesting for all non-vested LTIP performance shares was accelerated on a pro rata basis and such shares were cashed out at the $30.00 per share merger consideration price in accordance with the Merger agreement.

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Summarized performance share activity was as follows (note that there is no performance share activity after November 27, 2011 as a result of the Merger):

	Year ended December 31, 2011
Performance shares:
Outstanding at beginning of period		278,334
Granted		85,093
Dividends		(198,699	)
Exercised		(66,836	)
Forfeited		(97,892	)
Outstanding at end of period		—
Exercisable at end of period		—

The following table reflects information about performance share activity during the period (note that there is no performance share activity after November 27, 2011 as a result of the Merger):

	Year ended December 31, 2011
$ in millions
Weighted-average grant date fair value of performance shares granted during the period	$	2.2
Intrinsic value of performance shares exercised during the period	$	6.0
Proceeds from performance shares exercised during the period	$	—
Excess tax benefit from proceeds of performance shares exercised	$	0.7
Fair value of performance shares that vested during the period	$	4.7
Unrecognized compensation expense	$	—
Weighted-average period to recognize compensation expense (in years)		—

The following table shows the assumptions used in the Monte Carlo simulation to calculate the fair value of the performance shares granted during the period:

	Year ended December 31, 2011
$ in millions
Expected volatility		24.0	%
Weighted-average expected volatility		24.0	%
Expected life (years)		3.0
Expected dividends		5.0	%
Weighted-average expected dividends		5.0	%
Risk-free interest rate		1.2	%

Restricted Shares

Under the EPIP, the Board of Directors granted shares of DPL Restricted Shares to various executives and other key employees. These Restricted Shares were registered in the recipient’s name, carried full voting privileges, received dividends as declared and paid on all DPL common stock and vested after a specified service period.

In July 2008, the Board of Directors granted Restricted Share awards under the EPIP to a select group of management employees. The management Restricted Share awards had a three-year requisite service period, carried full voting privileges and received dividends as declared and paid on all DPL common stock.

On September 17, 2009, the Board of Directors approved a two-part equity compensation award under the EPIP for certain of DPL’s executive officers. The first part was a Restricted Share grant and the second part was a matching Restricted Share grant. These Restricted Share grants generally vested after five years if the participant remained continuously employed with DPL or a DPL subsidiary and if the year-over-year average EPS had increased by at

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Notes to Financial Statements

least 1% from 2009 to 2013. Under the matching Restricted Share grant, participants had a three-year period from the date of plan implementation during which they could purchase DPL common stock equal in value to up to two times their 2009 base salary. DPL matched the shares purchased with another grant of Restricted Shares (matching Restricted Share grant). The percentage match by DPL is detailed in the table below. The matching Restricted Share grant would have generally vested over a three-year period if the participant continued to hold the originally purchased shares and remained continuously employed with DPL or a DPL subsidiary. The Restricted Shares were registered in the recipient’s name, carried full voting privileges and received dividends as declared and paid on all DPL common stock.

The matching criteria were:

Value (Cost Basis) of Shared Purchased as a % of 2009 Base Salary	Company % Match of Value of Shares Purchased
1% to 25%	25%
>25% to 50%	50%
>50% to 100%	75%
>100% to 200%	125%

The matching percentage was applied on a cumulative basis and the resulting Restricted Share grant was adjusted at the end of each calendar quarter. As a result of the Merger, the matching Restricted Share grants were suspended in March 2011.

In February 2011, the Board of Directors granted a targeted number of time-vested Restricted Shares to executives under the LTIP. These Restricted Shares did not carry voting privileges nor did they receive dividend rights during the vesting period. In addition, a one-year holding period was implemented after the three-year vesting period was completed.

Restricted Shares could only be awarded in DPL common stock.

At the Merger date, vesting for all non-vested Restricted Shares was accelerated and all outstanding shares were cashed out at the $30.00 per share merger consideration price in accordance with the Merger agreement.

Summarized Restricted Share activity was as follows (note that there is no Restricted Share activity after November 27, 2011 as a result of the Merger):

	Year ended December 31, 2011
Restricted shares:
Outstanding at beginning of period		219,391
Granted		67,346
Exercised		(286,737	)
Forfeited		—
Outstanding at end of period		—

Exercisable at end of period		—

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Notes to Financial Statements

The following table reflects information about Restricted Share activity during the period (note that there is no Restricted Share activity after November 27, 2011 as a result of the Merger):

	Year ended December 31, 2011
$ in millions
Weighted-average grant date fair value of restricted shares granted during the period	$	1.8
Intrinsic value of restricted shares exercised during the period	$	8.6
Proceeds from restricted shares exercised during the period	$	—
Excess tax benefit from proceeds of restricted shares exercised	$	0.5
Fair value of restricted shares that vested during the period	$	7.5
Unrecognized compensation expense	$	—
Weighted-average period to recognize compensation expense (in years)		—

Non-Employee Director RSUs

Under the EPIP, as part of their annual compensation for service to DPL and DP&L, each non-employee Director received a retainer in RSUs on the date of the shareholders’ annual meeting. The RSUs became non-forfeitable on April 15 of the following year. The RSUs accrued quarterly dividends in the form of additional RSUs. Upon vesting, the RSUs became exercisable and were distributed in DPL common stock, unless the Director chose to defer receipt of the shares until a later date. The RSUs were valued at the closing stock price on the day prior to the grant and the compensation expense was recognized evenly over the vesting period.

At the Merger date, vesting for the remaining non-vested RSUs was accelerated and all vested RSUs (current and prior years) were cashed out at the $30.00 per share merger consideration price in accordance with the Merger agreement.

The following table reflects information about RSU activity (note that there is no non-employee Director RSU activity after November 27, 2011 as a result of the Merger):

	Year ended December 31, 2011
Restricted stock units:
Outstanding at beginning of period		16,320
Granted		14,392
Dividends accrued		3,307
Vested and exercised		(34,019	)
Vested, exercised and deferred		—
Forfeited		—
Outstanding at end of period		—

Exercisable at end of period		—

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The following table reflects information about non-employee Director RSU activity during the period (note that there is no non-employee Director RSU activity after November 27, 2011 as a result of the Merger):

	Year ended December 31, 2011
$ in millions
Weighted-average grant date fair value of non-employee Director RSUs granted during the period	$	0.5
Intrinsic value of non-employee Director RSUs exercised during the period	$	1.0
Proceeds from non-employee Director RSUs exercised during the period	$	—
Excess tax benefit from proceeds of non-employee Director RSUs exercised	$	—
Fair value of non-employee Director RSUs that vested during the period	$	1.0
Unrecognized compensation expense	$	—
Weighted-average period to recognize compensation expense (in years)		—

Management Performance Shares

Under the EPIP, the Board of Directors granted compensation awards for select management employees. The grants had a three year requisite service period and certain performance conditions during the performance period. The management performance shares could only be awarded in DPL common stock.

At the Merger date, vesting for all non-vested management performance shares was accelerated; some of the awards vested at target shares and other awards vested at a pro rata share of target. All vested shares were cashed out at the $30.00 per share merger consideration price in accordance with the Merger agreement.

Summarized management performance share activity was as follows (note that there is no management performance share activity after November 27, 2011 as a result of the Merger):

	Year ended December 31, 2011
Management performance shares:
Outstanding at beginning of period		104,124
Granted		49,510
Expired		(31,081	)
Exercised		(111,289	)
Forfeited		(11,264	)
Outstanding at end of period		—

Exercisable at end of period		—

The following table shows the assumptions used in the Monte Carlo simulation to calculate the fair value of the management performance shares granted during the period:

	Year ended December 31, 2011
$ in millions
Expected volatility		24.0	%
Weighted-average expected volatility		24.0	%
Expected life (years)		3.0
Expected dividends		5.0	%
Weighted-average expected dividends		5.0	%
Risk-free interest rate		1.2	%

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Notes to Financial Statements

The following table reflects information about management performance share activity during the period (note that there is no management performance share activity after November 27, 2011 as a result of the Merger):

	Year ended December 31, 2011
$ in millions
Weighted-average grant date fair value of management performance shares granted during the period	$	1.3
Intrinsic value of management performance shares exercised during the period	$	3.3
Proceeds from management performance shares exercised during the period	$	—
Excess tax benefit from proceeds of management performance shares exercised	$	—
Fair value of management performance shares that vested during the period	$	2.7
Unrecognized compensation expense	$	—
Weighted-average period to recognize compensation expense (in years)		—

Note 12 – 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, 2013. DP&L also has $25 par value preferred stock, 4,000,000 shares authorized, none of which was outstanding as of December 31, 2013. The table below details the preferred shares outstanding at December 31, 2013 and 2012:

				December 31, 2013 and 2012				Par Value ($ in millions)
	Preferred Stock Rate			Redemption price ($ per share)		Shares Outstanding		December 31, 2013		December 31, 2012
$ in millions except per share amounts
DP&L Series A		3.75	%	$	102.50		93,280	$	9.3	$	9.3
DP&L Series B		3.75	%	$	103.00		69,398		7.0		7.0
DP&L Series C		3.90	%	$	101.00		65,830		6.6		6.6
Total							228,508	$	22.9	$	22.9

The DP&L preferred stock may be redeemed at DP&L’s option as determined by its Board of Directors at the per-share redemption prices indicated above, plus cumulative accrued dividends. In addition, DP&L’s Amended Articles of Incorporation contain provisions that permit preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Since this potential redemption-triggering event is not solely within the control of DP&L, the preferred stock is presented on the Balance Sheets as “Redeemable Preferred Stock” in a manner consistent with temporary equity.

As long as any DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation also contain provisions restricting the payment of cash dividends on any of its common stock if, after giving effect to such dividend, the aggregate of all such dividends distributed subsequent to December 31, 1946 exceeds the net income of DP&L available for dividends on its common stock subsequent to December 31, 1946, plus $1.2 million. This dividend restriction has historically not impacted DP&L’s ability to pay cash dividends and, as of December 31, 2013, DP&L’s retained earnings of $426.8 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.

Note 13 – Common Shareholders’ Equity

DP&L has 250,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2013. All common shares are held by DP&L’s parent, DPL.

As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio of at least 50 percent and not to have a negative retained earnings balance.

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Note 14 – Contractual Obligations, Commercial Commitments and Contingencies

DP&L – Equity Ownership Interest

DP&L has a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. As of December 31, 2013, DP&L could be responsible for the repayment of 4.9%, or $76.4 million, of a $1,558.4 million debt obligation comprised of both fixed and variable rate securities with maturities between 2014 and 2040. This would only happen if this electric generation company defaulted on its debt payments. As of December 31, 2013, 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, 2013, these include:

	Payments due in:
	Total		Less than 1 year		2 - 3 years		4 - 5 years		More than 5 years
$ in millions
DP&L:
Long-term debt	$	877.8	$	0.2	$	445.2	$	0.2	$	432.2
Interest payments		361.0		24.1		48.4		31.7		256.8
Pension and postretirement payments		264.5		27.2		51.9		52.3		133.1
Operating leases		0.6		0.4		0.2		—		—
Coal contracts^(a)		625.6		216.5		270.3		138.8		—
Limestone contracts^(a)		24.4		6.1		12.2		6.1		—
Purchase orders and other contractual obligations		85.6		48.8		18.7		18.1		—
Total contractual obligations	$	2,239.5	$	323.3	$	846.9	$	247.2	$	822.1

(a)

Total at DP&L operated units.

Long-term debt:
DP&L’s long-term debt as of December 31, 2013, consists of first mortgage bonds and tax-exempt pollution control bonds. These long-term debt amounts include current maturities but exclude unamortized debt discounts.

See Note 6 for additional information.

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, 2013.

Pension and postemployment payments:

As of December 31, 2013, DP&L had estimated future benefit payments as outlined in Note 8. These estimated future benefit payments are projected through 2023.

Capital leases:
As of December 31, 2013, DP&L had one immaterial capital lease that expires in 2014.

Operating leases:
As of December 31, 2013, DP&L had several immaterial operating leases with various terms and expiration dates.

Coal contracts:
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.

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Limestone contracts:
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, 2013, 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 $8.8 million at December 31, 2013, 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.

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations, and other matters, including the matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2013, cannot be reasonably determined.

Environmental Matters

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

•

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

•

Rules and future rules issued by the USEPA and the Ohio EPA 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 may require reductions of GHGs,

•

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. The USEPA has previously determined that fly ash and other coal combustion by-products are not hazardous waste subject to the Resource Conservation and Recovery Act (RCRA), but the USEPA is reconsidering that determination and planning to propose a new rule regulating coal combustion by-products. A change in determination or other additional regulation of fly ash or other coal combustion byproducts could significantly increase the costs of disposing of such by-products.

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Accordingly, we have accruals for loss contingencies of approximately $1.1 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 of 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; especially the stations that do not have SCR and FGD equipment installed to further control certain emissions. Currently, the coal-fired generation unit Beckjord Unit 6, in which DP&L has a 50% ownership interest, does not have such emission-control equipment installed. This unit is scheduled to be deactivated on June 1, 2015. DPL valued Beckjord Unit 6 at zero at the Merger date. DP&L is depreciating Unit 6 through December 2014 and does not believe that any additional accruals or impairment charges are needed as a result of this decision.

DP&L deactivated the coal units at Hutchings Station in September 2013 as part of a settlement with the USEPA discussed in more detail below.

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 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 the “Clean Air Interstate Rule” (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 is 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 response to the D.C. Circuit's opinion, on July 7, 2011, the USEPA the Cross-State Air Pollution Rule (CSAPR). Starting in 2012, CSAPR would have required significant reductions in SO₂ and NO_x emissions from covered sources, such as power stations in 28 eastern states. Once fully implemented in 2014, the rule would have required additional SO₂ emission reductions of 73% and additional NO_x reductions of 54% from 2005 levels. Many states, utilities and other affected parties filed petitions for review, challenging the CSAPR before the U.S. Court of Appeals for the District of Columbia. 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 are to continue to serve as the governing program until the USEPA takes further action or the U.S. Congress intervenes. On October 5, 2012, the USEPA, several states and cities, as well as environmental and health organizations, filed petitions with the D.C. Circuit Court requesting a rehearing by all of the judges of the D.C. Circuit Court of the case pursuant to which the three-judge panel ruled that CSAPR be vacated, which were denied. On June 24, 2013, the U.S. Supreme Court agreed to review the D.C. Circuit Court’s decision to vacate CSAPR and heard oral arguments in the matter on December 10, 2013. Currently, CAIR remains in effect. If CSAPR were to be reinstated in its current form, we do not expect any material capital costs for DP&L’s stations, assuming Beckjord unit 6 will not operate on coal in 2015 due to implementation of the Mercury and Air Toxics Standards (MATS). If the USEPA issues a replacement

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Notes to Financial Statements

interstate transport rule addressing the D.C. Circuit Court’s ruling, we believe companies will have three years or more before they would be required to comply with a replacement rule. At this time, it is not possible to predict the details of such a replacement transport rule or what impacts it may have on our consolidated financial condition, results of operations or cash flows.

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, but may be granted an additional year to become compliant contingent on Ohio EPA approval. DP&L is evaluating the costs that may be incurred to comply with the new requirement; however, MATS could have a material adverse effect on our results of operations and result in material compliance costs.

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 redesignated Adams County, where Stuart and Killen are located, to attainment status. On December 14, 2012, the USEPA tightened the PM 2.5 standard to 12.0 micrograms per cubic meter. This will begin a process of redesignations during 2014, including in counties where we have generating stations. 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. The USEPA was expected to review the ozone NAAQS in 2013 but delayed such a review. Certain environmental groups have sued the USEPA in federal district court to force the USEPA to set a September 30, 2014 deadline for such review. It is generally expected that any revised standard resulting from such review would be more stringent than the current 0.075 ppm standard. In addition, in December 2013, eight northeastern states petitioned the USEPA to add nine upwind states, 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.

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.

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.

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Notes to Financial Statements

Carbon Dioxide and Other Greenhouse Gas Emissions

Under USEPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the USEPA began regulating GHG emissions from certain stationary sources in January 2011. The Tailoring Rule sets forth criteria for determining which facilities are required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration and Title V operating permit programs. Under the Tailoring Rule, permitting requirements are being phased in through successive steps that may expand the scope of covered sources over time. The USEPA has issued guidance on what the best available control technology entails for the control of GHGs; and individual states are required to determine what controls are required for facilities on a case-by-case basis. Various industry groups and states petitioned the U.S. Supreme Court to review the D.C. Circuit Court’s recent decision to uphold the USEPA’s endangerment finding, its April 2010 GHG rule and the Tailoring Rule. On October 15, 2013, the U.S. Supreme Court agreed to review several related cases addressing the USEPA’s authority to issue GHG Prevention of Significant Deterioration permits under Section 165 of the CAA. We cannot predict the outcome of this review. The ultimate impact of the Tailoring Rule to DP&L cannot be determined at this time, but the cost of compliance could be material.

On September 20, 2013, the USEPA proposed revised GHG New Source Performance Standards for new electric generating units (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. Furthermore, President Obama directed the USEPA to propose new standards, regulations, or guidelines, as appropriate, to address GHG emissions from existing EGUs under CAA subsection 111(d) by June 1, 2014, and finalize them by June 1, 2015. These latter rules may focus on energy efficiency improvements at power stations. We cannot predict the effect of these proposed or forthcoming standards on DP&L’s operations.

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
On June 20, 2011, the U.S. Supreme Court ruled that the USEPA’s regulation of GHGs under the CAA displaced any right that plaintiffs may have had to seek similar regulation through federal common law litigation in the court system. Although we are not named as a party to these lawsuits, DP&L is a co-owner of coal-fired stations with Duke Energy and AEP (or their subsidiaries) that could have been affected by the outcome of these lawsuits or similar suits that may have been filed against other electric power companies, including DP&L. Because the issue was not squarely before it, the U.S. Supreme Court did not rule against the portion of plaintiffs’ original suits that sought relief under state law.

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Notes to Financial Statements

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 November 1999, the USEPA filed civil complaints and NOVs against operators and owners of certain generation facilities for alleged violations of the CAA. Generation units operated by Duke Energy (Beckjord Unit 6) and AEP Generation (Conesville Unit 4) and co-owned by DP&L were referenced in these actions. The Conesville complaint was resolved in 2007 as part of a larger settlement with the USEPA. Conesville was required to install FGD and SCR at the unit by the end of 2010, and those retrofits have been completed. The Beckjord complaint was also resolved through litigation. There were no penalties or settlement agreements that affected Beckjord 6.

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 State Implementation Program (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. 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.

Notices of Violation Involving Wholly-Owned Stations
In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the Hutchings Station. The NOVs’ alleged deficiencies relate to stack opacity and particulate emissions. 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 at the Hutchings Station discussed in the next paragraph, DP&L believes that the USEPA is unlikely to pursue the NSR complaint.

As part of a settlement with the USEPA, DP&L signed a Consent Agreement and Final Order (CAFO) that was filed on September 26, 2013 and an Administrative Consent Agreement. Together, these two agreements resolved the opacity and particulate emissions NOV at the Hutchings Station and required that all six coal-fired units at Hutchings cease operating on coal by September 30, 2013, and included an immaterial penalty and the completion of a Supplemental Environmental Project of $0.2 million within one year. The units were disabled for coal operations prior to September 30, 2013.

DP&L also resolved all issues associated with the Ohio EPA NOV through a settlement signed October 4, 2013. The settlement included the payment of an immaterial penalty.

Environmental Matters Related to Water Quality, Waste Disposal and Ash Ponds

Clean Water Act – Regulation of Water Intake

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Notes to Financial Statements

The USEPA released new proposed regulations on March 28, 2011, which were published in the Federal Register on April 20, 2011. We submitted comments to the proposed regulations on August 17, 2011. The USEPA is required pursuant to a settlement agreement to issue a final rule by April 17, 2014. We do not yet know the impact the final rules will have on our operations.

Clean Water Act – Regulation of Water Discharge
In December 2006, DP&L submitted a renewal application for the Stuart 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. Depending on the outcome of the appeal process, the effects could be material on DP&L’s operations.

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. Subsequent to the information collection effort, it was anticipated that the USEPA would release a proposed rule by mid-2012 with a final regulation in place by early 2014. The proposed rule was released on June 7, 2013, with a deadline for a final rule on May 22, 2014, though such final rule’s issuance is expected to be delayed. At present, DP&L is unable to predict the impact this rulemaking will have on its operations.

In August 2012, DP&L submitted an application for the renewal of the Killen Station NPDES permit which expired in January 2013. At present, the outcome of this proceeding is not known.

In January 2014, DP&L submitted an application for the renewal of the Hutchings Station NPDES permit which expires in July 2014. At present, the outcome of this proceeding is not known.

In April 2012, DP&L received an NOV related to the construction of the Carter Hollow landfill at the Stuart Station. The NOV indicated that construction activities caused sediment to flow into downstream creeks. In addition, the U.S. Army Corps of Engineers issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill. DP&L installed sedimentation ponds as part of the runoff control measures to address this issue and worked with the various agencies to resolve their concerns. DP&L signed an Administrative Order from the USEPA on May 30, 2013. A final Consent Agreement and Final Order was executed on July 8, 2013, and the previously issued permit was reinstated by the Corps on October 29, 2013.

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. However, 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

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Notes to Financial Statements

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. That summary judgment ruling was appealed on March 4, 2013 and the appeal is pending. DP&L is unable to predict the outcome of the appeal. Additionally, the Court’s ruling 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.

Beginning in mid-2012, the USEPA began investigating whether explosive or other dangerous conditions exist under structures located at or near the South Dayton Dump landfill site. In October 2012, DP&L received a request from the PRP group’s consultant to conduct additional soil and groundwater sampling on DP&L’s service center property. After informal discussions with the USEPA, DP&L complied with this sampling request and the sampling was conducted in February 2013. On February 28, 2013, the plaintiffs group referenced above entered into an Administrative Settlement Agreement Consent Order (ASACO) that establishes procedures for further sub-slab testing under structures at the South Dayton Dump landfill site and remediation of vapor intrusion issues relating to trichloroethylene (TCE), percholorethylene (PCE), and methane. On April 16, 2013, the plaintiffs group filed a new complaint in the United States District Court for the Southern District of Ohio against DP&L and 34 other defendants alleging that they share liability for these costs. DP&L has opposed the allegations that it bears any responsibility under the February 2013 ASACO and will actively oppose any attempt that the plaintiffs group may have to expand the scope of the new complaint to resurrect issues dismissed by the Court in February 2013 under the first complaint. A motion to dismiss portions of this second complaint relating to alleged migration of chemicals from DP&L property to the landfill was denied February 18, 2014, as were motions filed by DP&L and others to dismiss other portions of the complaint that were viewed by defendants as identical to the allegations dismissed in the first complaint proceeding. The Judge found that there were differences in the allegations and is permitting those allegations to proceed.. Limited discovery has been permitted pending resolution of the motion including some depositions of former DP&L employees during 2013 and into 2014. DP&L cannot predict the outcome of this proceeding.

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. While the USEPA previously indicated that the official release date for a proposed rule was in April 2013, it has been delayed, likely until late 2014. 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.

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Notes to Financial Statements

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 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 byproducts 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. Litigation has been filed by several groups seeking a court-ordered deadline for the issuance of a final rule which the USEPA has opposed. On January 29, 2014, the parties to the litigation entered into a consent decree setting forth the USEPA’s obligation to sign, by December 19, 2014, a notice for publication in the Federal Register taking action on the Agency’s proposed Subtitle D option. The decree does not require Subtitle D regulation of coal combustion byproducts – it only requires the Agency to decide by that date whether or not to adopt the Subtitle D option. At present, the timing for a final rule regulating coal combustion byproducts cannot be determined. DP&L is unable to predict the financial effect of this regulation, but if coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse effect on its operations.

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 Clean Water Act 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 against a coal supplier seeking damages incurred due to the supplier’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. The supplier 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 resolves 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 $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.

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Notes to Financial Statements

Note 15 – Fixed-asset Impairment

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

On October 5, 2012, DP&L filed for approval an ESP with the PUCO which reflects a shift in our outlook for the regulatory environment. Within the ESP filing, DP&L agreed to request a separation of its generation assets from its transmission and distribution assets in recognition that a restructuring of DP&L operations will be necessary, in compliance with Ohio law. Also, during 2012, North American natural gas prices fell significantly from the previous year, exerting downward pressure on wholesale electricity prices in the Ohio power market. Falling power prices have compressed wholesale margins at DP&L’s generating stations. Furthermore, these lower power prices have led to increased customer switching from DP&L to CRES providers, who are offering retail prices lower than DP&L’s standard service offer. Also, several municipalities in DP&L’s service territory have passed ordinances allowing them to become government aggregators with some having already contracted with CRES providers, further contributing to the switching trend. In September 2012, management revised its cash flow forecasts based on these developments as part of its annual budgeting process and forecasted lower operating cash flows than in prior reporting periods. Collectively, in the third quarter of 2012, these events were considered to be an impairment indicator for the long-lived asset group as management believes that these developments represent a significant adverse change in the business climate that could affect the value of the long-lived asset group.

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. When the recoverability test of the long-lived asset group was performed, management concluded that, on an undiscounted cash flow basis, the carrying amount of two stations, Conesville and Hutchings, were not recoverable. To measure the amount of impairment loss, management was required to determine the fair value of the two stations. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. While there were numerous assumptions that impact the fair value, forward power prices, dark spreads and the transition to a merchant model were the most significant.

In determining the fair value of the Conesville station, the three valuation approaches prescribed by the fair value measurement accounting guidance were considered. The fair value under the income approach was considered the most appropriate and resulted in a $25.0 million fair value. The carrying value of the Conesville station prior to the impairment was $97.5 million. Accordingly, the Conesville station was considered impaired and $72.5 million of impairment expense was recognized in the third quarter of 2012.

In determining the fair value of the Hutchings Station, the three valuation approaches prescribed by the fair value measurement accounting guidance were considered. The fair value under the income approach was considered the most appropriate and resulted in a zero fair value. The carrying value of the Hutchings Station prior to the impairment was $8.3 million. Accordingly, the Hutchings Station was considered impaired and $8.3 million of impairment expense was recognized in the third quarter of 2012.

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Notes to Financial Statements

Note 16 – Selected Quarterly Information (Unaudited)

From 2012 onwards, quarterly information is no longer required.

	For the 2011 quarters ended
	March 31		June 30		September 30		December 31
$ in millions except per share amounts and common stock market price
Revenues	$	449.8	$	397.0	$	452.5	$	378.4
Operating income	$	89.3	$	55.8	$	100.0	$	74.8
Net income	$	52.7	$	30.8	$	63.9	$	45.8
Earnings on common stock	$	52.5	$	30.6	$	63.7	$	45.5
Dividends paid on common stock to DPL	$	70.0	$	45.0	$	65.0	$	40.0

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Schedule II

THE DAYTON POWER AND LIGHT COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the years ended Year ended December 31, 2011 - 2013

Description	Balance at Beginning of Period		Additions		Deductions^(a)		Balance at End of Period
$ in thousands
Year ended December 31, 2013
Deducted from accounts receivable -
Provision for uncollectible accounts	$	923	$	4,924	$	4,938	$	909

Year ended December 31, 2012
Deducted from accounts receivable -
Provision for uncollectible accounts	$	941	$	5,393	$	5,411	$	923

Year ended December 31, 2011
Deducted from accounts receivable -
Provision for uncollectible accounts	$	832	$	6,137	$	6,028	$	941

(a)

Amounts written off, net of recoveries of accounts previously written off.

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CONDENSED STATEMENTS OF RESULTS OF OPERATIONS

	Three months ended March 31,
	2014			2013
$ in millions
Revenues	$	432.1		$	376.5

Cost of revenues:
Fuel		84.3			88.1
Purchased power		168.0			94.1
Total cost of revenues		252.3			182.2

Gross margin		179.8			194.3

Operating expenses:
Operation and maintenance		95.4			91.3
Depreciation and amortization		36.5			33.6
General taxes		26.4			19.8
Total operating expenses		158.3			144.7

Operating income		21.5			49.6

Other income / (expense), net:
Investment income		0.3			0.1
Interest expense		(7.8	)		(9.3	)
Other expense		(0.6	)		(0.6	)
Total other expense		(8.1	)		(9.8	)

Earnings before income taxes		13.4			39.8

Income tax expense		4.0			9.6

Net income		9.4			30.2
Dividends on preferred stock		0.2			0.2

Income attributable to common stock	$	9.2		$	30.0

See Notes to Condensed Financial Statements. These interim statements are unaudited.

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CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

	Three months ended March 31,
	2014			2013
$ in millions
Net income	$	9.4		$	30.2

Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax (expense) / benefit of $0.2 and $(0.2) for each respective period		(0.3	)		0.2
Reclassification to earnings, net of income tax expense of $(0.1) and $(0.1) for each respective period		0.2			0.1
Total change in fair value of available-for-sale securities		(0.1	)		0.3

Derivative activity:
Change in derivative fair value, net of income tax benefit of $7.0 and $1.4 for each respective period		(12.9	)		(2.6	)
Reclassification to earnings, net of income tax expense of $(3.2) and $(0.2) for each respective period		5.7			(0.2	)
Total change in fair value of derivatives		(7.2	)		(2.8	)

Pension and postretirement activity:
Prior service cost for the period net of income tax expense of $0.0 and $(0.5), for each respective period		—			0.9
Reclassification to earnings, net of income tax expense of $(0.4) and $0.0 for each respective period		0.6			—
Total change in unfunded pension obligation		0.6			0.9

Other comprehensive loss		(6.7	)		(1.6	)

Net comprehensive income	$	2.7		$	28.6

See Notes to Condensed Financial Statements. These interim statements are unaudited.

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CONDENSED STATEMENTS OF CASH FLOWS

	Three months ended March 31,
	2014			2013
$ in millions
Cash flows from operating activities:
Net income	$	9.4		$	30.2
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		36.5			33.6
Deferred income taxes		1.4			22.9
Changes in certain assets and liabilities:
Accounts receivable		(14.8	)		13.2
Inventories		(10.3	)		(4.3	)
Prepaid taxes		0.3			—
Taxes applicable to subsequent years		13.5			16.7
Deferred regulatory costs, net		(5.7	)		3.6
Accounts payable		34.0			2.7
Accrued taxes payable		(21.5	)		(25.3	)
Accrued interest payable		(5.8	)		2.3
Pension, retiree and other benefits		0.8			3.2
Unamortized investment tax credit		(0.6	)		(0.6	)
Other		(27.0	)		3.6
Net cash from operating activities		10.2			101.8

Cash flows from investing activities:
Capital expenditures		(27.4	)		(33.6	)
Purchase of emission allowances		(0.1	)		—
Purchase of renewable energy credits		(1.2	)		(0.5	)
Increase in restricted cash		(16.0	)		(12.7	)
Net cash used for investing activities		(44.7	)		(46.8	)

Net cash from financing activities:
Dividends paid on common stock to parent		—			(55.0	)
Issuance of notes payable - related party		15.0			—
Dividends paid on preferred stock		(0.2	)		(0.2	)
Net cash from financing activities		14.8			(55.2	)

Cash and cash equivalents:
Net change		(19.7	)		(0.2	)
Balance at beginning of period		22.9			28.5
Cash and cash equivalents at end of period	$	3.2		$	28.3

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	12.8		$	7.9
Income taxes refunded, net	$	(0.3	)	$	(20.0	)
Non-cash financing and investing activities:
Accruals for capital expenditures	$	9.4		$	10.6

See Notes to Condensed Financial Statements. These interim statements are unaudited.

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CONDENSED BALANCE SHEETS

	March 31, 2014			December 31, 2013
$ in millions
ASSETS

Current assets:
Cash and cash equivalents	$	3.2		$	22.9
Restricted cash		29.0			13.0
Accounts receivable, net (Note 2)		162.6			147.5
Inventories (Note 2)		89.6			81.7
Taxes applicable to subsequent years		55.0			68.5
Regulatory assets, current (Note 3)		32.4			20.8
Other prepayments and current assets		66.0			32.5
Total current assets		437.8			386.9

Property, plant & equipment:
Property, plant & equipment		5,124.0			5,105.3
Less: Accumulated depreciation and amortization		(2,482.8	)		(2,448.1	)
		2,641.2			2,657.2
Construction work in process		65.3			60.9
Total net property, plant & equipment		2,706.5			2,718.1

Other non-current assets:
Regulatory assets, non-current (Note 3)		153.2			159.7
Intangible assets, net of amortization		9.5			8.3
Other deferred assets		36.1			40.1
Total other non-current assets		198.8			208.1

Total assets	$	3,343.1		$	3,313.1

See Notes to Condensed Financial Statements. These interim statements are unaudited.

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CONDENSED BALANCE SHEETS

	March 31, 2014			December 31, 2013
$ in millions
LIABILITIES AND SHAREHOLDER'S EQUITY

Current liabilities:
Current portion of long-term debt (Note 5)	$	0.2		$	0.2
Notes payable - related party (Note 5)		15.0			—
Accounts payable		102.7			73.9
Accrued taxes		91.1			81.0
Accrued interest		3.9			9.6
Customer security deposits		33.6			33.1
Other current liabilities		68.8			59.7
Total current liabilities		315.3			257.5

Non-current liabilities:
Long-term debt (Note 5)		876.9			876.9
Deferred taxes		629.2			632.3
Taxes payable		45.0			76.5
Regulatory liabilities, non-current		123.6			121.1
Pension, retiree and other benefits		51.1			51.6
Unamortized investment tax credit		24.3			24.9
Other deferred credits		48.5			45.4
Total non-current liabilities		1,798.6			1,828.7

Redeemable preferred stock		22.9			22.9

Commitments and contingencies (Note 11)

Common shareholder's equity:
Common stock, at par value of $0.01 per share:		0.4			0.4
Other paid-in capital		803.3			803.5
Accumulated other comprehensive loss		(33.4	)		(26.7	)
Retained earnings		436.0			426.8
Total common shareholder's equity		1,206.3			1,204.0

Total liabilities and shareholder's equity	$	3,343.1		$	3,313.1

See Notes to Condensed Financial Statements. These interim statements are unaudited.

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The Dayton Power and Light Company
Notes to Condensed Financial Statements (Unaudited)

1. Overview and Summary of Significant Accounting Policies

Description of Business

DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L is engaged in the generation, transmission, distribution and sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L's SSO customers is primarily generated at seven coal-fired power plants and DP&L distributes electricity to more than 516,000 retail customers. During 2014, DP&L is required to source 10% of the generation for its standard service offer customers through a competitive bid process. Principal industries located in DP&L’s service area include food processing, paper, plastic manufacturing and defense. DP&L is a wholly owned subsidiary of DPL.

DP&L's retail generation sales reflect the general economic conditions, seasonal weather patterns of the area and retail competition in the area. DP&L sells any excess energy and capacity into the wholesale market.

On March 19, 2014, the PUCO issued a second entry on rehearing which shortened the time by which DP&L must divest its generation assets to no later than January 1, 2016, terminated the potential extension of the SSR on April 30, 2017 instead of May 31, 2017, and accelerated DP&L’s phase-in of the competitive bidding structure to 10% in 2014, 60% in 2015 and 100% in 2016. Parties, including DP&L, have filed applications for rehearing on this Commission Order that are currently pending.

DP&L employed 1,189 people as of March 31, 2014. Approximately 63% of all employees are under a collective bargaining agreement which expires on October 31, 2014.

Financial Statement Presentation

DP&L does not have any subsidiaries. DP&L has undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities which are included in the financial statements at amortized cost. Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Statements of Results of Operations. See Note 4 for more information.

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, 2013.

In the opinion of our management, the Condensed Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31, 2014; our results of operations for the three months ended March 31, 2014 and 2013 and our cash flows for the three months ended March 31, 2014 and 2013. 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, 2014 may not be indicative of our results that will be realized for the full year ending December 31, 2014.

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

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The Dayton Power and Light Company
Notes to Condensed Financial Statements (Unaudited)

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, such as with our CCEM energy efficiency program. Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DP&L expects to incur in the future.

Property, Plant & Equipment

We record our ownership share of our undivided interest in jointly-held plants as an asset in property, plant and equipment. Property, plant and equipment are stated at cost except for the impact of asset impairments recorded for certain generating plants. 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 including unregulated generation property, cost is similarly defined except financing costs are reflected as capitalized interest without an equity component. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators.

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.

Intangibles

Intangibles consist of emission allowances and renewable energy credits. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the carrying value of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. Emission allowances are amortized as they are used in our operations. Renewable energy credits are amortized as they are used or retired. During the three months ended March 31, 2014 and 2013, gains from the sale of emission allowances were immaterial.

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

DP&L collects certain excise taxes levied by state or local governments from its customers. These taxes are accounted for on a net basis and are recorded as a reduction in revenues. The amounts of such taxes collected for the three months ended March 31, 2014 and 2013 were $14.4 million and $13.4 million, respectively.

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

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The Dayton Power and Light Company
Notes to Condensed Financial Statements (Unaudited)

of companies that are part of the US SBU, including, among other companies, 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 regulatory utilities served, including DP&L, are not subsidizing costs incurred for the benefit of non-regulated businesses.

In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL and AES. The following table provides a summary of these transactions:

	Three months ended March 31,
	2014			2013
$ in millions
DP&L Revenues:
Sales to DPLER^(a)	$	107.8		$	78.7
Sales to MC Squared^(b)	$	31.0		$	25.6
DP&L Operations and Maintenance Expenses:
Premiums paid for insurance services provided by MVIC^(c)	$	(0.8	)	$	(0.7	)
Expense recoveries for services provided to DPLER^(d)	$	—		$	1.1
Transactions with the Service Company
Charges for services provided	$	11.4		$	—

	At March 31,
	2014		2013
DP&L Customer security deposits:
Deposits received from DPLER^(e)	$	19.2	$	19.2
Transactions with the Service Company
Advances and Prepaids to the Service Company^(f)	$	5.4	$	—
Payables to the Service Company^(g)	$	11.4	$	—

(a)

DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers. The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements. The increase in DP&L’s sales to DPLER during the three months ended March 31, 2014, compared to the three months ended March 31, 2013, is primarily due to increase in customers.

(b)

DP&L also sells power to MC Squared to satisfy the electric requirements of MC Squared’s retail customers. The revenue dollars associated with sales to MC Squared are recorded as wholesale revenues in DP&L’s Financial Statements. The increase in DP&L’s sales to MC Squared during the three months ended March 31, 2014, compared to the three months ended March 31, 2013, is primarily due to the increase of customers.

(c)

MVIC, a wholly owned captive insurance subsidiary of DPL, provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC.

(d)

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

(e)

(f)

DP&L has advanced funds to the Service Company which will be applied against future charges for services

(g)

As the Service Company charges for services, amounts not offset against advances are recorded as liabilities

Recently Issued 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 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

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The Dayton Power and Light Company
Notes to Condensed Financial Statements (Unaudited)

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. This new rule is not expected to have a material effect on our overall results of operations, financial position or cash flows.

2. Supplemental Financial Information

Accounts receivable and Inventories are as follows at March 31, 2014 and December 31, 2013:

	March 31, 2014			December 31, 2013
$ in millions
Accounts receivable, net:
Unbilled revenue	$	41.0		$	47.2
Customer receivables		76.9			58.2
Amounts due from partners in jointly owned plants		20.2			15.8
Other		25.5			27.2
Provision for uncollectible accounts		(1.0	)		(0.9	)
Total accounts receivable, net	$	162.6		$	147.5
Inventories, at average cost:
Fuel and limestone	$	50.9		$	42.9
Plant materials and supplies		36.9			37.0
Other		1.8			1.8
Total inventories, at average cost	$	89.6		$	81.7

Accumulated Other Comprehensive Income / (Loss)

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

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Statements of Operations	Three months ended March 31,
		2014			2013
$ in millions
Gains and losses on Available-for-sale securities activity (Note 8):
	Other income / (deductions)	$	0.3		$	0.2
	Total before income taxes		0.3			0.2
	Tax expense		(0.1	)		(0.1	)
	Net of income taxes		0.2			0.1
Gains and losses on cash flow hedges (Note 9):
	Interest expense		(0.3	)		(0.6	)
	Revenue		(1.0	)		(0.5	)
	Purchased power		10.2			1.1
	Total before income taxes		8.9			—
	Tax expense		(3.2	)		(0.2	)
	Net of income taxes		5.7			(0.2	)
Amortization of defined benefit pension items (Note 7):
	Reclassification to Other income / (deductions)		1.0			—
	Tax benefit		(0.4	)		—
	Net of income taxes		0.6			—
Total reclassifications for the period, net of income taxes		$	6.5		$	(0.1	)

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The Dayton Power and Light Company
Notes to Condensed Financial Statements (Unaudited)

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the three months ended March 31, 2014 are as follows:

Gains / (losses) on available-for-sale securities

Gains / (losses) on cash flow hedges

Change in unfunded pension obligation

Total

$ in millions

Balance January 1, 2014

0.8

6.2

(33.7

)

(26.7

)

Other comprehensive loss before reclassifications

(0.3

)

(12.9

)

—

(13.2

)

Amounts reclassified from accumulated other comprehensive income / (loss)

0.2

5.7

0.6

6.5

Net current period other comprehensive loss

(0.1

)

(7.2

)

0.6

(6.7

)

Balance March 31, 2014

0.7

(1.0

)

(33.1

)

(33.4

)

3. Regulatory Assets

DP&L’s regulatory asset for deferred storm costs represents costs incurred to repair the damage caused to DP&L’s transmission and distribution equipment by major storms in 2008, 2011 and 2012. Such costs are included in Regulatory Assets, non-current on the accompanying Condensed Consolidated Balance Sheets and were $22.3 million and $25.6 million as of March 31, 2014 and December 31, 2013, respectively. DP&L filed an application with the PUCO in 2012 to recover these costs. The main issue in the case is the level of storm costs that should be recoverable. On April 14, 2014, DP&L reached an agreement in principle with the PUCO Staff whereby DP&L would recover storm costs of $22.3 million from all customers on a non-bypassable basis. Once the stipulation is finalized, it will be filed at the PUCO and a hearing may still be required if all parties do not sign or agree to not oppose the stipulation. As a result of these developments, we reduced the asset balance to $22.3 million as our best estimate of the amount that is probable of recovery. In accordance with FASC 980 “Regulated Operations”, the reduction was recognized as a current period expense, which is included in Operation and maintenance on the accompanying Condensed Statements of Results of Operations.

4. Ownership of Coal-fired Facilities

DP&L has undivided ownership interests in seven coal-fired electric generating 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 the energy taken. 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 March 31, 2014, DP&L had $27.0 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 Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant & equipment in the Condensed Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly owned unit or station.

DP&L’s undivided ownership interest in such facilities at March 31, 2014, is as follows:

	DP&L Share				DP&L 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)
Beckjord Unit 6		50.0		207	$	75	$	70	$	—		No
Conesville Unit 4		16.5		129		20		1		1		Yes
East Bend Station		31.0		186		1		1		2		Yes
Killen Station		67.0		402		622		306		2		Yes
Miami Fort Units 7 and 8		36.0		368		360		154		1		Yes
Stuart Station		35.0		808		745		312		18		Yes
Zimmer Station		28.1		365		1,099		661		3		Yes
Transmission (at varying percentages)				n/a		98		61		—
Total				2,465	$	3,020	$	1,566	$	27

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The Dayton Power and Light Company
Notes to Condensed Financial Statements (Unaudited)

Currently, our coal-fired generation unit at Beckjord does not have SCR and FGD emission-control equipment installed. DP&L has a 50% interest in Beckjord Unit 6. On July 15, 2011, Duke Energy, a co-owner at the Beckjord Unit 6 facility, filed its Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord Station, including our jointly owned Unit 6, in December 2014. This was followed by a notification by the joint owners to PJM, dated April 12, 2012, of a planned June 1, 2015 deactivation of this unit.

5. Debt Obligations

Long-term debt

	March 31, 2014			December 31, 2013
$ in millions
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: 0.04% - 0.08% and 0.05% - 0.24% (a)		100.0			100.0
First mortgage bonds due in September 2016 - 1.875%		445.0			445.0
U.S. Government note due in February 2061 - 4.2%		18.2			18.2
Unamortized debt discount		(0.7	)		(0.7	)
Total non-current portion of long-term debt	$	876.9		$	876.9

Current portion of long-term debt

	March 31, 2014		December 31, 2013
$ in millions
U.S. Government note due in February 2061 - 4.2%		0.1	$	0.1
Capital lease obligations		0.1		0.1
Total current portion of long-term debt	$	0.2	$	0.2

(a)

Range of interest rates for the three months ended March 31, 2014 and the twelve months ended December 31, 2013, respectively.

At March 31, 2014, maturities of long-term debt, including capital lease obligations, are as follows:

Due within the twelve months ending March 31,:
$ in millions
2015	$	0.2
2016		0.1
2017		445.1
2018		0.1
2019		0.1
Thereafter		432.2
		877.8
Unamortized discounts		(0.7	)
Total long-term debt	$	877.1

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The Dayton Power and Light Company
Notes to Condensed Financial Statements (Unaudited)

JPMorgan Chase Bank, N.A. DP&L amended these standby letters of credit on May 31, 2013 and extended the stated maturities to June 2018. These amended facilities are irrevocable, have no subjective acceleration clauses and remain subject to terms and conditions that are substantially similar to those of the pre-existing facilities. Fees associated with these standby letter of credit facilities were not material during the three months ended March 31, 2014 and 2013.

On May 10, 2013, DP&L closed 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. DP&L had no outstanding borrowings under this facility at September 30, 2013. At September 30, 2013, there was a letter of credit in the amount of $0.4 million outstanding, with the remaining $299.6 million available to DP&L. Fees associated with this revolving credit facility were not material during the three months ended March 31, 2014.

On September 19, 2013, DP&L closed a $445.0 million issuance of senior secured first mortgage bonds. These bonds mature on September 15, 2016, and are secured by DP&L’s First & Refunding Mortgage.

DP&L’s unsecured revolving credit agreements and DP&L’s standby letter of credit had one financial covenant which measured 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. DP&L’s new unsecured revolving credit agreement and DP&L’s amended standby letters of credit maintain the Total Debt to Total Capitalization financial covenant and add the EBITDA to Interest Expense ratio as a second financial covenant. 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. DP&L financed the acquisition of these assets with an unsecured note payable to the federal government that is payable monthly over 50 years and bears interest at 4.2% per annum.

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

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

6. Income Taxes

The following table details the effective tax rates for the three months ended March 31, 2014 and 2013.

	Three months ended March 31,
	2014			2013
DP&L		29.9	%		24.1	%

Income tax expense for the three months ended March 31, 2014 and 2013 was calculated using the estimated annual effective income tax rates for 2014 and 2013 of 30.6% and 28.8%, respectively. For the three months ended March 31, 2014 and 2013 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, 2013, DP&L’s current period effective rate is less than the estimated annual effective rate due primarily to a favorable resolution of the 2008 Internal Revenue Service examination in the first quarter of 2013 and the deferred tax adjustment related to the expiration of the statute of limitations on the 2007, 2008 and 2009 tax years.

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The Dayton Power and Light Company
Notes to Condensed Financial Statements (Unaudited)

7. 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 the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. There were no contributions made during the three months ended March 31, 2014 or 2013, respectively.

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 net periodic benefit cost / (income) of the pension and postretirement benefit plans for the three months ended March 31, 2014 and 2013 was:

Net Periodic Benefit Cost / (Income)	Pension						Postretirement
	Three months ended March 31,						Three months ended March 31,
	2014			2013			2014			2013
$ in millions
Service cost	$	1.5		$	1.8		$	—		$	0.1
Interest cost		4.4			3.9			0.2			0.2
Expected return on plan assets^(a)		(5.7	)		(5.9	)		—			(0.1	)
Amortization of unrecognized:
Prior service cost		0.7			0.7			—			—
Actuarial loss / (gain)		1.6			2.3			(0.2	)		(0.1	)
Net periodic benefit cost	$	2.5		$	2.8		$	—		$	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 included in 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 for the 2014 and 2013 net periodic benefit cost was approximately $351 million and $346 million, respectively.

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

	Pension		Postretirement
$ in millions
2014	$	18.8	$	1.6
2015		23.9		2.1
2016		23.9		2.0
2017		24.3		1.8
2018		24.6		1.6
2019 - 2023		126.5		6.7

8. Fair Value Measurements

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The Dayton Power and Light Company
Notes to Condensed Financial Statements (Unaudited)

The following table presents the fair value and cost of our non-derivative instruments at March 31, 2014 and December 31, 2013. See also Note 9 for the fair values of our derivative instruments.

	March 31, 2014				December 31, 2013
	Carrying Value		Fair Value		Carrying Value		Fair Value
$ in millions
Assets
Money market funds	$	0.1	$	0.1	$	0.3	$	0.3
Equity securities		2.8		3.7		3.3		4.4
Debt securities		4.8		4.9		5.4		5.5
Hedge funds		0.8		0.9		0.9		0.9
Real estate		0.4		0.4		0.4		0.4
Total assets	$	8.9	$	10.0	$	10.3	$	11.5
Liabilities
Debt	$	877.1	$	878.6	$	877.1	$	859.6

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 cost.

Debt

The fair value of debt is based on current public market prices for disclosure purposes only. Unrealized gains or losses are not recognized in the financial statements because debt is presented at amortized cost in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2028 to 2061.

Master Trust Assets

DP&L established Master Trusts to hold assets that could be used for the benefit of employees participating in employee benefit plans and these assets are not used for general operating purposes. These assets are primarily comprised of open-ended mutual funds which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.

DP&L had $1.0 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at March 31, 2014 and $1.2 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2013.

During the three months ended March 31, 2014, $0.3 million ($0.2 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 disbursement of benefits.

Net Asset Value (NAV) per Unit

The following table presents the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of March 31, 2014 and December 31, 2013. These assets are part of the Master Trusts. Fair values estimated using the NAV per unit are primarily considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV per unit on the reporting date. Investments that have restrictions on the redemption of the investments are Level 3 inputs. At March 31, 2014, DP&L did not have any investments for sale at a price different from the NAV per unit.

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Notes to Condensed Financial Statements (Unaudited)

Fair Value Estimated Using Net Asset Value per Unit
	Fair Value at March 31, 2014		Fair Value at December 31, 2013		Unfunded Commitments		Redemption Frequency
$ in millions
Money market fund^(a)	$	0.1	$	0.3	$	—	Immediate
Equity securities^(b)		3.7		4.4		—	Immediate
Debt securities^(c)		4.9		5.5		—	Immediate
Hedge funds^(d)		0.9		0.9		—	Quarterly
Real estate^(e)		0.4		0.4		—	Quarterly
Total	$	10.0	$	11.5	$	—

(a)

This category includes investments in high-quality, short-term securities. Investments in this category can be redeemed immediately at the current NAV.

(b)

(c)

This category includes investments in U.S. Treasury obligations and U.S. investment grade bonds. Investments in this category can be redeemed immediately at the current NAV per unit.

(d)

(e)

This category includes EFT real estate funds that invest in U.S. and International properties.

Fair Value Hierarchy

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as Level 1 (quoted prices in active markets for identical assets or liabilities); Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or Level 3 (unobservable inputs).

The fair value of assets and liabilities at March 31, 2014 and December 31, 2013 measured on a recurring basis and the respective category within the fair value hierarchy for DP&L was determined as follows:

Assets and Liabilities at Fair Value on a Recurring Basis

Level 1

Level 2

Level 3

Fair Value at
March 31, 2014

Based on Quoted
Prices in Active Markets

Other
Observable Inputs

Unobservable
Inputs

$ in millions

Assets

Master trust assets

Money market funds

0.1

—

Equity securities

3.7

—

3.7

—

Debt securities

4.9

—

4.9

—

Hedge funds

0.9

—

0.9

—

Real estate

0.4

—

0.4

—

Total Master trust assets

10.0

0.1

9.9

—

Derivative assets

FTRs

—

Heating Oil

0.1

—

Forward power contracts

20.0

—

20.0

—

Total derivative assets

20.1

0.1

20.0

—

Total assets

30.1

0.2

29.9

—

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Assets and Liabilities at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
	Fair Value at March 31, 2014		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs

Liabilities
Derivative liabilities
FTRs	$	0.1	$	—	$	—	$	0.1
Forward power contracts		33.5		—		33.5		—
Total derivative liabilities		33.6		—		33.5		0.1
Long-term debt		878.6		—		860.2		18.4
Total liabilities	$	912.2	$	—	$	893.7	$	18.5

Assets and Liabilities at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
	Fair Value at December 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
$ in millions
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		0.3		11.2		—
Derivative assets
Heating oil futures		0.2		0.2		—		—
FTRs		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	$	0.5	$	24.6	$	0.2
Liabilities
Derivative liabilities
Forward power contracts		10.6		—		10.6		—
Total Derivative liabilities		10.6		—		10.6		—
Long-term debt		859.6		—		841.1		18.5
Total liabilities	$	870.2	$	—	$	851.7	$	18.5

We use the market approach to value our financial instruments. 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. FTRs are considered a Level 3 input because the monthly auctions are considered inactive.

Our Level 3 inputs are immaterial to our derivative balances as a whole, and as such no further disclosures are presented.

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leases and the Wright-Patterson Air Force Base loan are not publicly traded. Fair value is assumed to equal carrying value. These fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures are not presented since debt is not recorded at fair value.

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

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. Additions to AROs for the three months ended March 31, 2014 were $1.2 million for asbestos and underground storage tank AROs. Additions to AROs were not material during the three months ended March 31, 2013.

9. Derivative Instruments and Hedging Activities

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

Commodity	Accounting Treatment	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Mark to Market	MWh		14.6		—			14.6
Heating oil futures	Mark to Market	Gallons		1,428.0		—			1,428.0
Forward power contracts	Cash Flow Hedge	MWh		193.2		(4,427.7	)		(4,234.5	)
Forward power contracts	Mark to Market	MWh		3,408.6		(3,561.8	)		(153.2	)

At December 31, 2013, DP&L 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		3,172.4		(2,888.5	)		283.9

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.

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The following tables provide information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended March 31, 2014 and 2013:

	Three months ended March 31, 2014						Three months ended March 31, 2013
	Power			Interest Rate Hedge			Power			Interest Rate Hedge
$ in millions (net of tax)
Beginning accumulated derivative gain / (loss) in AOCI	$	1.0		$	5.2		$	(4.7	)	$	7.3
Net gains / (losses) associated with current period hedging transactions		(12.9	)		—			(2.6	)		—
Net gains / (losses) reclassified to earnings
Interest expense		—			(0.3	)		—			(0.6	)
Revenues		6.6			—			(0.3	)		—
Purchased power		(0.6	)		—			0.7			—
Ending accumulated derivative gain / (loss) in AOCI	$	(5.9	)	$	4.9		$	(6.9	)	$	6.7

Net losses associated with the ineffective portion of the hedging transaction are presented in the following lines of the Condensed Statements of Results of Operations:
Portion expected to be reclassified to earnings in the next twelve months^(a)	$	(13.1	)	$	(1.2	)
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 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 Condensed Statements of Results of Operations in the period in which the change occurred. This is commonly referred to as “MTM accounting.” Contracts we enter into as part of our risk management program may be settled financially, by physical delivery, or net settled with the counterparty. FTRs, heating oil futures, forward NYMEX-quality coal contracts and certain forward power contracts are marked to market.

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

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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.

The following tables present the amount and classification within the Condensed Statements of Results of Operations or Condensed Balance Sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the three months ended March 31, 2014 and 2013:

For the three months ended March 31, 2014

Heating Oil

FTRs

Power

Total

$ in millions

Change in unrealized loss

(0.1

)

(0.3

)

(5.5

)

(5.9

)

Realized gain / (loss)

0.1

—

(1.4

)

(1.3

)

Total

—

(0.3

)

(6.9

)

(7.2

)

Recorded on Balance Sheet:

Regulatory (asset) / liability

—

Recorded in Income Statement: gain / (loss)

Revenues

—

0.8

Purchased power

—

(0.3

)

(7.7

)

(8.0

)

Fuel

—

O&M

—

Total

—

(0.3

)

(6.9

)

(7.2

)

For the three months ended March 31, 2013
	FTRs		Power			Total
$ in millions
Change in unrealized gain / (loss)	$	—	$	(10.4	)	$	(10.4	)
Realized gain		0.5		0.7			1.2
Total	$	0.5	$	(9.7	)	$	(9.2	)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	—	$	—		$	—
Regulatory (asset) / liability		—		—			—
Recorded in Income Statement: gain / (loss)
Revenues		—		(1.1	)		(1.1	)
Purchased power		0.5		(8.6	)		(8.1	)
Fuel		—		—			—
O&M		—		—			—
Total	$	0.5	$	(9.7	)	$	(9.2	)

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

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The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged.

Fair Values of Derivative Instruments at March 31, 2014

Gross Amounts Not Offset
in the Condensed Balance Sheets

Hedging
Designation

Gross Fair
Value as
presented
in the
Condensed
Balance
Sheets

Financial
Instruments
with Same
Counterparty
in Offsetting
Position

Cash
Collateral

Net
Amount

$ in millions

Assets

Short-term derivative positions (presented in Other current assets)

Forward power contracts

Cash Flow

1.1

(1.0

)

—

0.1

Forward power contracts

MTM

12.3

(10.1

)

—

2.2

Heating oil futures

MTM

0.1

—

0.1

FTRs

MTM

—

Long-term derivative positions (presented in Other deferred assets)

Forward power contracts

Cash Flow

2.8

(0.1

)

—

2.7

Forward power contracts

MTM

3.8

(2.3

)

—

1.5

Total assets

20.1

(13.5

)

—

6.6

Liabilities

Short-term derivative positions (presented in Other current liabilities)

Forward power contracts

Cash Flow

13.9

(1.0

)

(10.6

)

2.3

Forward power contracts

MTM

16.7

(10.1

)

(5.1

)

1.5

FTRs

MTM

0.1

—

0.1

Long-term derivative positions (presented in Other deferred liabilities)

Forward power contracts

Cash Flow

0.1

(0.1

)

—

Forward power contracts

MTM

2.8

(2.3

)

(0.3

)

0.2

Total liabilities

33.6

(13.5

)

(16.0

)

4.1

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Notes to Condensed Financial Statements (Unaudited)

The following table presents the fair value and balance sheet classification of DP&L’s derivative instruments at December 31, 2013:

Fair Values of Derivative Instruments at December 31, 2013
				Gross Amounts Not Offset in the Condensed Balance Sheets
	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Amount
$ in millions
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

The aggregate fair value of DP&L’s commodity derivative instruments that were in a MTM loss position at March 31, 2014 was $33.6 million. 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. If our debt does not maintain an investment grade credit rating, our counterparties to the derivative instruments could request immediate payment or immediate and full overnight collateralization of the MTM loss. The MTM loss positions at March 31, 2014 were offset by $16.0 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $13.5 million. If our counterparties were to call for collateral, DP&L could be required to post collateral for the remaining $4.1 million.

10. Shareholder’s Equity

DP&L has 250,000,000 authorized $0.01 par value common shares, of which 41,172,173 are outstanding at March 31, 2014. All common shares are held by DP&L’s parent, DPL.

11. Contractual Obligations, Commercial Commitments and Contingencies

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, 2014, DP&L could be responsible for the repayment

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Notes to Condensed Financial Statements (Unaudited)

of 4.9%, or $76.0 million, of a $1,550.2 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, 2014, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Condensed Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of March 31, 2014, cannot be reasonably determined.

Environmental Matters

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

•

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

•

Rules and future rules issued by the USEPA and the Ohio EPA that require reporting and may require reductions of GHGs,

•

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. The USEPA has previously determined that fly ash and other coal combustion by-products are not hazardous waste subject to the Resource Conservation and Recovery Act (RCRA), but the USEPA is reconsidering that determination and planning to propose a new rule regulating coal combustion by-products. A change in determination or other additional regulation of fly ash or other coal combustion byproducts could significantly increase the costs of disposing of such 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 in an effort to comply, or to determine compliance, with such regulations. We record liabilities for environmental losses that are probable of occurring and can be reasonably estimated At March 31, 2014, and December 31, 2013, we had accruals of approximately $1.4 million and $1.1 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

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Notes to Condensed Financial Statements (Unaudited)

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 EGUs and stations. Some of these matters could have material adverse effects on the operation of the power stations; especially on those that do not have SCR and FGD equipment installed to further control certain emissions. Currently, the coal-fired generation unit Beckjord Unit 6, in which DP&L has a 50% ownership interest, does not have such emission-control equipment installed. This unit is scheduled to be deactivated on June 1, 2015. DP&L is depreciating Beckjord Unit 6 through December 2014 and does not believe that any additional accruals or impairment charges are needed as a result of this decision.

Environmental Matters Related to Air Quality

Clean Air Act Compliance

Clean Air Interstate Rule/Cross-State Air Pollution Rule

The USEPA promulgated the “Clean Air Interstate Rule” (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 is 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 response to the D.C. Circuit's opinion, on July 7, 2011, the USEPA issued the Cross-State Air Pollution Rule (CSAPR). Starting in 2012, CSAPR would have required significant reductions in SO₂ and NO_x emissions from covered sources, such as power stations in 28 eastern states. Once fully implemented in 2014, the rule would have required additional SO₂ emission reductions of 73% and additional NO_x reductions of 54% from 2005 levels. Many states, utilities and other affected parties filed petitions for review, challenging the CSAPR before the U.S. Court of Appeals for the District of Columbia. 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 are to continue to serve as the governing program until the USEPA takes further action or the U.S. Congress intervenes. On October 5, 2012, the USEPA, several states and cities, as well as environmental and health organizations, filed petitions with the D.C. Circuit Court requesting a rehearing by all of the judges of the D.C. Circuit Court of the case pursuant to which the three-judge panel ruled that CSAPR be vacated, which were denied. On June 24, 2013, the U.S. Supreme Court agreed to review the D.C. Circuit Court’s decision to vacate CSAPR. On April 29, 2014, the U.S. Supreme Court upheld CSAPR, remanding the case back to the D.C. Circuit Court for further proceedings. At this time, it is not possible to predict the details of such a replacement transport rule or what impacts it may have on our consolidated financial condition, results of operations or cash flows.

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

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Notes to Condensed Financial Statements (Unaudited)

into compliance with the new requirements by April 16, 2015, but may be granted an additional year to become compliant contingent on Ohio EPA approval. DP&L is evaluating the costs that may be incurred to comply with the new requirement; however, MATS could have a material adverse effect on our results of operations and result in material compliance costs.

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 redesignated Adams County, where Stuart and Killen are located, to attainment status. On December 14, 2012, the USEPA tightened the PM 2.5 standard to 12.0 micrograms per cubic meter. This will begin a process of redesignations during 2014. 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. DP&L cannot determine the effect of revisions to the ozone standard, if any, on its operations; however, no DP&L operations are located in non-attainment areas. The USEPA is required to review the ozone standard and is expected to propose a more stringent standard in 2014 or 2015. In addition, in December 2013, eight northeastern states petitioned the USEPA to add nine upwind states, 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.

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 revisions to its primary NAAQS for SO₂ replacing the current 24-hour standard and annual standard with a one-hour standard. DP&L cannot determine the effect of this potential change, if any, on its operations. Initial non-attainment designations were made July 25, 2013, and Pierce Township in Clermont County, which contains DP&L’s co-owned unit Beckjord 6, was the only area with DP&L operations recommended as non-attainment. Non-attainment areas will be required to meet the new standard by October 2018. DP&L cannot determine the effect of the designations on its operations; however, Beckjord is expected to cease operations prior to the attainment date.

Carbon Dioxide and Other Greenhouse Gas Emissions

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Notes to Condensed Financial Statements (Unaudited)

2010. Numerous affected parties have petitioned the USEPA Administrator to reconsider this decision. On April 1, 2010, the USEPA signed the “Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards” rule. Under the USEPA’s view, this is the final action that renders CO₂ and certain other GHGs “regulated air pollutants” under the CAA.

Litigation, Notices of Violation and Other Matters Related to Air Quality

Litigation Involving Co-Owned Stations

On June 20, 2011, the U.S. Supreme Court ruled that the USEPA’s regulation of GHGs under the CAA displaced any right that plaintiffs may have had to seek similar regulation through federal common law litigation in the court system. Although we are not named as a party to these lawsuits, DP&L is a co-owner of coal-fired stations with Duke Energy and AEP (or their subsidiaries) that could have been affected by the outcome of these lawsuits or similar suits that may have been filed against other electric power companies, including DP&L. Because the issue was not squarely before it, the U.S. Supreme Court did not rule against the portion of plaintiffs’ original suits that sought relief under state law.

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.

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Notes to Condensed Financial Statements (Unaudited)

Notices of Violation Involving Co-Owned Units

In November 1999, the USEPA filed civil complaints and NOVs against operators and owners of certain generation facilities for alleged violations of the CAA. Generation units operated by Duke Energy (Beckjord Unit 6) and AEP Generation (Conesville Unit 4) and co-owned by DP&L were referenced in these actions. The Conesville complaint was resolved in 2007 as part of a larger settlement with the USEPA. Conesville was required to install FGD and SCR at the unit by the end of 2010, and those retrofits have been completed. The Beckjord complaint was also resolved through litigation. There were no penalties or settlement agreements that affected Beckjord Unit 6.

Notices of Violation Involving Wholly-Owned Stations

In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the Hutchings Station. The NOVs’ alleged deficiencies relate to stack opacity and particulate emissions. 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 at the Hutchings Station discussed in the next paragraph, DP&L believes that the USEPA is unlikely to pursue the NSR complaint.

DP&L also resolved all issues associated with the Ohio EPA NOV through a settlement signed October 4, 2013. The settlement included the payment of an immaterial penalty.

Environmental Matters Related to Water Quality, Waste Disposal and Ash Ponds

Clean Water Act – Regulation of Water Intake

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pursuant to a settlement agreement to issue a final rule by April 17, 2014. On April 16, 2014, the agency released a letter sent to the Court indicating the final rulemaking would be completed by May 16, 2014. We do not yet know the impact the final rules will have on our operations.

Clean Water Act – Regulation of Water Discharge

In December 2006, DP&L submitted a renewal application for the Stuart 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 and a hearing before the Commission on the appeal is scheduled for August 2014. The outcome of the appeal could have a material effect on DP&L’s operations.

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. Subsequent to the information collection effort, it was anticipated that the USEPA would release a proposed rule by mid-2012 with a final regulation in place by early 2014. The proposed rule was released on June 7, 2013, with a deadline for a final rule on May 22, 2014. On December 16, 2013, the USEPA filed a status report that indicated that the agency is negotiating for an extension of time to finalize proposed revisions to the rule. On April 17, 2014, the parties entered into an agreement extending the deadline for the final regulations to September 30, 2015. At present, DP&L is unable to predict the impact this rulemaking will have on its operations.

In August 2012, DP&L submitted an application for the renewal of the Killen Station NPDES permit which expired in January 2013. At present, the outcome of this proceeding is not known.

In January 2014, DP&L submitted an application for the renewal of the Hutchings Station NPDES permit which expires in July 2014. At present, the outcome of this proceeding is not known.

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

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or PRP status. However, 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. That summary judgment ruling was appealed on March 4, 2013 and the appeal is pending. DP&L is unable to predict the outcome of the appeal. Additionally, the Court’s ruling 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.

Beginning in mid-2012, the USEPA began investigating whether explosive or other dangerous conditions exist under structures located at or near the South Dayton Dump landfill site. In October 2012, DP&L received a request from the PRP group’s consultant to conduct additional soil and groundwater sampling on DP&L’s service center property. After informal discussions with the USEPA, DP&L complied with this sampling request and the sampling was conducted in February 2013. On February 28, 2013, the plaintiffs group referenced above entered into an Administrative Settlement Agreement Consent Order (ASACO) that establishes procedures for further sub-slab testing under structures at the South Dayton Dump landfill site and remediation of vapor intrusion issues relating to trichloroethylene (TCE), perchloroethylene (PCE), and methane. On April 16, 2013, the plaintiffs group filed a new complaint in the United States District Court for the Southern District of Ohio against DP&L and 34 other defendants alleging that they share liability for these costs. DP&L has opposed the allegations that it bears any responsibility under the February 2013 ASACO and will actively oppose any attempt that the plaintiffs group may have to expand the scope of the new complaint to resurrect issues dismissed by the Court in February 2013 under the first complaint. A motion to dismiss portions of this second complaint relating to alleged migration of chemicals from DP&L property to the landfill was denied February 18, 2014, as were motions filed by DP&L and others to dismiss other portions of the complaint that were viewed by defendants as identical to the allegations dismissed in the first complaint proceeding. The Judge found that there were differences in the allegations and is permitting those allegations to proceed. Limited discovery has been permitted pending resolution of the motion including some depositions of former DP&L employees during 2013 and into 2014. DP&L cannot predict the outcome of this proceeding.

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 the USEPA previously indicated that the official release date for a proposed rule was in April 2013, it has been delayed, likely until late 2014. At present, DP&L is unable to predict the impact this initiative will have on its operations.

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Regulation of Ash Ponds

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.

There has been increasing advocacy to regulate coal combustion byproducts 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. Litigation has been filed by several groups seeking a court-ordered deadline for the issuance of a final rule which the USEPA has opposed. On January 29, 2014, the parties to the litigation entered into a consent decree setting forth the USEPA’s obligation to sign, by December 19, 2014, a notice for publication in the Federal Register taking action on the agency’s proposed Subtitle D option. The decree does not require Subtitle D regulation of coal combustion byproducts – it only requires the agency to decide by that date whether or not to adopt the Subtitle D option. At present, the timing for a final rule regulating coal combustion byproducts cannot be determined. DP&L is unable to predict the financial effect of this regulation, but if coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse effect on its operations.

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 Clean Water Act 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 which was done in October 2011. 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.

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Offer to Exchange

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