DPL 10K 2005 Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

SECURITIES EXCHANGE ACT OF 1934

ý For the fiscal year ended December 31, 2005

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 1-9052

DPL INC.

(Exact name of registrant as specified in its charter)

OHIO		31-1163136
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

1065 Woodman Drive, Dayton, Ohio		45432
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: 937-224-6000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock, $0.01 par value and Preferred Share Purchase Rights		New York Stock Exchange

Outstanding at

February 28, 2006

126,556,404

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ý No o

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

Yes o No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

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

Large accelerated filer ý

Accelerated filer o

Non-accelerated filer o

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

Yes o No ý

The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant as of June 30, 2005 was approximately $3.5 billion based on a closing sale price on that date as reported on the New York Stock Exchange.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for its 2006 Annual Meeting of Shareholders are incorporated by reference in Part III of this Form 10-K.

DPL INC.

Index to Annual Report on Form 10-K

Fiscal Year Ended December 31, 2005

		Page No.
	Part I
Item 1	Business	3
Item 1a	Risk Factors	17
Item 1b	Unresolved Staff Comments	21
Item 2	Properties	21
Item 3	Legal Proceedings	22
Item 4	Submission of Matters to a Vote of Security Holders	25

	Part II
Item 5	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	25
Item 6	Selected Financial Data	27
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	47
Item 8	Financial Statements and Supplementary Data	48
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	94
Item 9A	Controls and Procedures	94
Item 9B	Other Information	94

	Part III
Item 10	Directors and Executive Officers of the Registrant	94
Item 11	Executive Compensation	95
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	95
Item 13	Certain Relationships and Related Transactions	95
Item 14	Principal Accountant Fees and Services	95

	Part IV
Item 15	Exhibits and Financial Statement Schedules	96

	Other
	Signatures	103
	Schedule II Valuation and Qualifying Accounts	105
	Subsidiaries of DPL Inc.
	Consent of Independent Registered Public Accounting Firm

Available Information

DPL Inc. (DPL, the Company, we, us, our, or ours unless the context indicates otherwise) files current, annual and quarterly reports, proxy statements and other information required by the Securities Exchange Act of 1934, as amended, with the Securities and Exchange Commission (SEC). You may read and copy any document we file at the SEC’s public reference room located at 100 F Street N.E., Washington, D.C. 20549, USA. Please call the SEC at (800) SEC-0330 for further information on the public reference rooms. Our SEC filings are also available to the public from the SEC’s web site at http://www.sec.gov.

Our public internet site is http://www.dplinc.com. We make available, free of charge, through our internet site, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and Forms 3, 4 and 5 filed on behalf of our directors and executive officers and amendments to those reports filed or furnished pursuant to the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

In addition, our public internet site includes other items related to corporate governance matters, including, among other things, our governance guidelines, charters of various committees of the Board of Directors and our code of business conduct and ethics applicable to all employees, officers and directors. You may obtain copies of these documents, free of charge, by sending a request, in writing, to DPL Investor Relations, 1065 Woodman Drive, Dayton, Ohio 45432.

PART I

Item 1 – Business

DPL INC.

We are a diversified regional energy company organized in 1985 under the laws of Ohio. Our executive offices are located at 1065 Woodman Drive, Dayton, Ohio 45432 - telephone (937) 224-6000.

Our principal subsidiary is The Dayton Power and Light Company (DP&L). DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. DP&L also purchases retail peak load requirements from DPL Energy LLC (DPLE, one of our wholly-owned subsidiaries). Principal industries served include automotive, food processing, paper, plastic manufacturing, and defense. DP&L’s sales reflect the general economic conditions and seasonal weather patterns of the area. DP&L sells any excess energy and capacity into the wholesale market.

Our significant subsidiaries (all of which are wholly-owned) include DPLE, which engages in the operation of peaking generating facilities; DPL Energy Resources, Inc. (DPLER), which sells retail electric energy under contract to major industrial and commercial customers in West Central Ohio; MVE, Inc., which was primarily responsible for the management of our financial asset portfolio; DPL Finance Company, Inc., which provides financing to us and our subsidiaries; and Miami Valley Insurance Company (MVIC), our captive insurance company that provides insurance sources to us and our subsidiaries.

We conduct our principal business in one business segment - Electric.

Under the recently-enacted Public Utility Holding Company Act of 2005, the Federal Energy Regulatory Commission (FERC) requires that utility holding companies comply with certain accounting, record retention and filing requirements. We believe we are exempt from these requirements because DP&L’s operations are confined to a single state. On January 31, 2006, we filed a FERC 65B Waiver Notification with the FERC, requesting that the FERC approve our waiver and avoid FERC regulation.

DPL and our subsidiaries employed 1,381 persons as of December 31, 2005, of which 1,147 were full-time employees and 234 were part-time employees.

SIGNIFICANT DEVELOPMENTS

Sale of Private Equity Funds

On February 13, 2005, our subsidiaries, MVE and MVIC, entered into an agreement to sell their respective interests in forty-six private equity funds to AlpInvest/Lexington 2005, LLC, a joint venture of AlpInvest Partners and Lexington Partners, Inc. Sales proceeds and any related gains or losses were recognized as the sale of each fund closed. Among other closing conditions, each fund required the transaction to be approved by the respective general partner. During 2005, MVE and MVIC completed the sale of their interests in forty-three private equity funds and a portion of one private equity fund resulting in a $46.6 million pre-tax gain ($53.1 million less $6.5 million professional fees) from discontinued operations and providing approximately $796 million in net proceeds, including approximately $52 million in distributions from funds while held for sale. As part of this pre-tax gain, we realized $30 million that was previously recorded as an unrealized gain in other comprehensive income.

During this same period, MVE entered into alternative closing arrangements with AlpInvest/Lexington 2005, LLC for funds where legal title to said funds could not be transferred until a later time. Pursuant to these arrangements, MVE transferred the economic aspects of the remaining private equity funds, consisting of two funds and a portion of another fund, to AlpInvest/Lexington 2005, LLC without a change in ownership of the interests. The terms of the alternative arrangements do not meet the criteria for recording a sale. We are obligated to remit to AlpInvest/Lexington 2005, LLC any distributions MVE receives from these funds, and AlpInvest/Lexington 2005, LLC is obligated to provide funds to us to pay any contribution notice, capital call or other payment notice or bill for which MVE receives notice with respect to such funds. The alternative arrangements resulted in a deferred gain of $27.1 million until such terms of a sale can be completed (contingent upon receipt of general partner approvals of the transfer) and provided approximately $72.3 million in net proceeds on these funds. We recorded an impairment loss of $5.6 million to write down to estimated fair value the assets transferred pursuant to the alternative arrangements. Ownership of these funds will transfer after the general partners of each of the separate funds consent to the transfer. It is anticipated that this will occur no later than the first quarter of 2007.

Debt Reduction

During 2005 we used part of the proceeds from the sale of its private equity funds to retire all or part of four outstanding long-term debt issues in the aggregate amount of $446.6 million as described below.

On May 15, 2005 we redeemed all of the outstanding 7.83% Senior Notes due 2007 in the amount of $39 million. A premium of 5.38% was paid on the 7.83% Senior Notes that were redeemed.

On July 14, 2005, we extended an Offer to Purchase three debt securities for a maximum aggregate purchase price of $246 million. The Offer to Purchase was made in three tiers. The first tier was to purchase all the tendered 8.125% Capital Securities due 2031 up to the aggregate purchase price of $246 million. The second tier was to purchase as many of the tendered 6.875% Senior Notes due 2011 with funds remaining from the aggregate purchase price. If any funds were still remaining, the third tier was to purchase as many as possible of the tendered 8.0% Senior Notes due 2009.

On August 11, 2005, we executed the results of the Offer to Purchase and purchased $105.0 million of the 8.125% Capital Securities, $102.6 million of the 6.875% Senior Notes and none of the 8.0% Senior Notes. Premiums of 26.46% and 10.32% were paid on the 8.125% Capital Securities and on the 6.875% Senior Notes, respectively, that were tendered and accepted for purchase.

On August 29, 2005, we executed a make whole call option and purchased $200 million of the 8.25% Senior Notes due 2007. A premium of 5.69% was paid on the 8.25% Senior Notes that were tendered and accepted for purchase.

Stock Repurchase Plan

On July 27, 2005, our Board authorized the repurchase up to $400 million of stock from time to time in the open market through private transactions. During December 2005, a total of 406,000 shares at a cost of $10.6 million were repurchased and settled in January 2006. These shares are currently held as treasury shares. There were no other repurchases during 2005 and 2004.

Rate Stabilization Surcharge

On April 4, 2005, DP&L filed a request at the Public Utilities Commission of Ohio (PUCO) to implement a new rate stabilization surcharge effective January 1, 2006 to recover cost increases associated with environmental capital and related Operations and Maintenance costs, and fuel expenses. On November 3, 2005, DP&L entered into a settlement agreement that extended DP&L’s rate stabilization period through December 31, 2010. During this time, the Company will continue to provide retail electric service at fixed rates with the ability to recover increased fuel and environmental costs through surcharges and riders. Specifically, the agreement provides for:

• A rate stabilization surcharge equal to 11% of generation rates beginning January 1, 2006 and continuing through December 2010. Based on 2004 sales, this rider is expected to result in approximately $65 million in net revenues per year.

• A new environmental investment rider to begin January 1, 2007 equal to 5.4% of generation rates, with incremental increases equal to 5.4% each year through 2010. Based on 2004 sales, this rider is expected to result in approximately $35 million in annual net revenues beginning January 2007, growing to approximately $140 million by 2010.

• An increase to the residential generation discount from January 1, 2006 through December 31, 2008 which is expected to result in a revenue decrease of approximately $7 million per year for three years, based on 2004 sales. The residential discount will expire on December 31, 2008.

On December 28, 2005, the PUCO adopted the settlement with certain modifications (RSS Stipulation). The PUCO ruled that the environmental rider will be bypassable by all customers who take service from alternate generation suppliers. Future additional revenues are dependent upon actual sales and levels of customer switching. On February 22, 2006, the PUCO denied applications for rehearing filed by the Office of the Ohio Consumers’ Counsel (OCC), as well as Ohio Partners for Affordable Energy.

Collective Bargaining Agreement Ratification

On December 2, 2005, Local 175 of the Utility Workers of America ratified a new three year collective bargaining agreement with DP&L. Major components include: 3%, 2% and 2.5% annual wage increases over three years, improvements to the pension and 401(k) programs, increases in DP&L’s contribution to employees’ healthcare costs, employment security for three years, measurable productivity and service improvements, an emergency response program targeted to enhance customer service response time and changes in DP&L’s illness benefits. On December 31, 2005, 760 employees were members of Local 175.

Increase in Dividends on Common Stock

On February 1, 2006, our Board of Directors announced that it had raised the quarterly dividend to $0.25 per share payable March 1, 2006 to common shareholders of record on February 14, 2006. This increase results in an annualized dividend rate of $1.00 per share, or a 4% increase.

Governmental and Regulatory Inquiries

On April 7, 2004, we received notice that the staff of the PUCO was conducting an investigation into the financial condition of DP&L as a result of previously disclosed matters raised by one of our executives during the 2003 year-end financial closing process (the Memorandum). On May 27, 2004, the PUCO ordered DP&L to file a plan of utility financial integrity that outlined the actions the Company had taken or will take to insulate DP&L utility operations and customers from its unregulated activities. DP&L was required to file this plan by March 2, 2005. On February 4, 2005, DP&L filed its protection plan with the PUCO. On June 29, 2005, the PUCO closed its investigation citing significant positive actions we had taken including changes in our Board of Directors as well as our executive management of DP&L, and that no apparent diminution of service quality had occurred because of the events that initiated the investigation.

On May 20, 2004, the staff of the SEC notified us that it was conducting an inquiry covering our exempt status under the Public Utility Holding Company Act of 1935 (the ‘35 Act). The staff of the SEC requested we provide certain documents and information on a voluntary basis. On October 8, 2004, we received a notice from the SEC that a question existed as to whether such exemption from the Public Utility Holding Company Act was detrimental to the public interest or the interests of investors or consumers. On November 5, 2004, we filed a good faith application seeking an order of exemption from the SEC. In light of the repeal of the ‘35 Act, effective February 8, 2006, and based upon the information previously provided to the staff of the SEC, this inquiry is moot.

On March 3, 2005, DP&L received a notice that the Federal Energy Regulatory Commission (FERC) had instituted an operational audit of DP&L regarding its compliance with the Code of Conduct within the transmission and generation areas. On October 7, 2005, the FERC issued its Findings and Conclusions, stating that DP&L “generally complied with the FERC Standard of Conduct” except for three areas, all of which were corrected to the satisfaction of the FERC prior to the issuance of these Findings and Conclusions.

Sale of Warrants and Repurchase of Voting Preferred Shares

As a result of an investment made by Dayton Ventures, LLC, an affiliate of Kohlberg, Kravis & Roberts & Co. (KKR), in March 2000, Dayton Ventures, LLC owned 31,560,000 warrants. During the twelve

year period commencing March 13, 2000, each warrant can be exercised and converted into a common share of our common stock for an exercise price of $21.00. Additionally, as a part of Dayton Ventures, LLC’s investment in us, we sold and issued 6,800,000 shares of voting preferred shares, 200,000 shares of which we redeemed in 2001. During December 2004 and January 2005 in four transactions, Dayton Ventures, LLC transferred all of its warrants to an unaffiliated third party which has subsequently transferred approximately 25 million warrants to unaffiliated third parties. In conjunction with transactions in 2005, we repurchased at par of $0.01 per share all of the outstanding 6,600,000 voting preferred shares. As a result of the reduction of Dayton Ventures, LLC’s warrant ownership below 12,640,000, KKR was no longer eligible to receive an annual $1 million management, consulting and financial services fee and Dayton Ventures, LLC no longer had the right to designate one person to serve as a DPL and DP&L director or to designate one person to serve as a non-voting observer on DPL and DP&L Boards of Directors.

COMPETITION AND REGULATION

DP&L has historically operated in a rate-regulated environment providing electric generation and energy delivery, consisting of transmission and distribution services, as a single product to its retail customers. Prior to the legislation discussed below, DP&L did not have retail competitors in its service territory.

In October 1999, legislation became effective in Ohio that gave electric utility customers a choice of energy providers beginning on January 1, 2001. Under this legislation, electric generation, power marketing, and power brokerage services supplied to retail customers in Ohio are deemed to be competitive and are not subject to supervision and regulation by the PUCO.

DP&L filed an Electric Transition Plan with the PUCO and received regulatory approval of the plan on September 21, 2000 which provided for a three-year market development period and specified rates, which included the recovery of approximately $600 million in transition costs.

On October 28, 2002, DP&L filed with the PUCO a request for an extension of its market development period through December 31, 2005. On September 2, 2003, the PUCO adopted a Stipulation entered into by DP&L and certain parties to the proceeding with modifications (the MDP Stipulation). The MDP Stipulation also provided that beginning January 1, 2006, rates may be modified by up to 11% of generation rates to reflect increased costs associated with fuel, environmental compliance, taxes, regulatory changes, and security measures. Further, the PUCO conditionally approved an increase to the residential generation discount commencing January 1, 2006. The PUCO’s decision was appealed to the Ohio Supreme Court. On December 17, 2004, the Ohio Supreme Court affirmed the PUCO’s Order, approving the MDP Stipulation.

As a part of the MDP Stipulation, DP&L agreed to implement a Voluntary Enrollment Process that would provide customers with an option to choose a competitive supplier to provide their retail generation service should switching not reach 20% in each customer class by October 2004. During 2005, approximately 51 thousand residential customers that volunteered for the program were bid out to Competitive Retail Electric Service (CRES) providers who were registered in DP&L’s service territory. In August 2005, the fourth and final bid took place, however no bids were received and the 2005 program ended. As part of the RSS Stipulation, DP&L agreed to implement the Voluntary Enrollment Program again in 2006 and 2007. The magnitude of any customer switching and the financial impact of this program were not material to our results of operations, cash flows or financial position in 2005. Future period effects cannot be determined at this time.

On February 20, 2003, the PUCO requested comments from interested stakeholders on the proposed rules for the conduct of a competitive bidding process that will take place at the end of the rate stabilization period. DP&L submitted comments in March 2003. The PUCO issued final rules on December 23, 2003. Under DP&L’s RSS Stipulation discussed above, these rules will not affect DP&L until January 1, 2011. However, the PUCO retains the authority to, at any time, require an Ohio electric utility to conduct a competitive bidding process to measure the market price of competitive retail generation.

As of December 31, 2005, four unaffiliated marketers were registered as CRES providers in DP&L’s service territory; to date, there has been no significant activity from these suppliers. DPL Energy Resources, Inc. (DPLER), an affiliated company, is also a registered CRES provider and accounted for nearly all load served by CRES providers within DP&L’s service territory in 2005. In addition, several communities in DP&L’s service area have passed ordinances allowing the communities to become government aggregators for the purpose of offering alternative electric generation supplies to their citizens. To date, none of these communities have aggregated their generation load.

There was a complaint filed on January 21, 2004 at the PUCO concerning the pricing of DP&L’s billing services. Previously, on December 16, 2003, a complaint was filed at the PUCO alleging that DP&L had established improper barriers to competition. On October 13, 2004, the parties reached a settlement on the pricing of DP&L’s billing services that DP&L will charge CRES providers. Additionally, on October 19, 2004, DP&L entered into a settlement that resolves all matters in the barrier to competition complaint. This settlement provides that DP&L will modify the manner in which customer partial payments are applied to billing charges and DP&L will no longer offer to purchase the receivables of CRES providers who operate in DP&L’s certified territory. On February 2, 2005, the PUCO issued an Order approving both settlements with minor modifications. This Order gives DP&L the right to defer costs of approximately $16 million and later file for recovery over a five year period, subject to PUCO approval. The Office of the Ohio Consumers’ Counsel (OCC) filed a Motion for Rehearing which was later denied by the PUCO and on May 23, 2005, the OCC appealed the order to the Ohio Supreme Court. On June 17, 2005, DP&L filed a subsequent case, requesting PUCO approval for recovery of the deferred billing costs plus carrying charges beginning January 1, 2006. If approved as proposed, this new rider will result in approximately $7 million in additional annual revenue through 2010. A hearing was held on January 23, 2006, and a PUCO decision is pending in this case. On August 16, 2005, the OCC filed a Complaint against DP&L in Mercer County Common Pleas Court relating to billing costs that may be charged to residential customers. DP&L filed a motion to dismiss the case. On February 24, 2006, the OCC filed a notice of voluntary dismissal of the Mercer County proceeding.

On September 1, 2005, DP&L filed an application requesting the PUCO grant it authority to recover distribution costs associated with storm restoration efforts for ice storms that took place in December

2004 and January 2005. On February 10, 2006, DP&L filed updated schedules in support of its application upon discussions with PUCO Staff. If approved as proposed, this new rider is designed to recover over $6.5 million in previously deferred costs plus carrying costs for a total of $8.6 million over a two year period. (See Note 3 of Notes to Consolidated Financial Statements.)

Like other electric utilities and energy marketers, DP&L and DPLE may sell or purchase electric products on the wholesale market. DP&L and DPLE compete with other generators, power marketers, privately and municipally-owned electric utilities, and rural electric cooperatives when selling electricity. The ability of DP&L and DPLE to sell this electricity will depend on how DP&L’s and DPLE’s price, 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 are required to join a Regional Transmission Organization (RTO). In October 2004, DP&L successfully integrated its 1,000 miles of high-voltage transmission into the PJM Interconnection, L.L.C. (PJM) RTO. The role of the RTO is to administer an electric marketplace and insure reliability. PJM ensures the reliability of the high-voltage electric power system serving 51 million people in all or parts of Delaware, Indiana, Illinois, Kentucky, Maryland, Michigan, New Jersey, 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.

As a member of PJM, the value of DP&L’s generation capacity may be affected by a PJM proposal pending before The Federal energy Regulatory Commission (FERC). The proposal introduces a new Reliability Pricing Model (RPM) that would change the way generation capacity is priced and planned for by PJM. The outcome of this proceeding is uncertain at this time.

DP&L provides transmission and wholesale electric service to twelve municipal customers in its service territory, which distribute electricity principally within their incorporated limits. DP&L also maintains an interconnection agreement with one municipality that has the capability to generate a portion of its own energy requirements. Sales to these municipalities represented less than 1% of total electricity sales in 2005. DP&L’s contract with one municipality expired in February 2005, creating reduced future generation sales to municipalities.

As of December 31, 2004, DP&L had invested a total of approximately $18.0 million in its efforts to join an RTO. On March 8, 2005, DP&L, along with Commonwealth Edison and American Electric Power Service Corporation, filed to recover a portion of integration expenses to join an RTO. On May 6, 2005, FERC approved the filing subject to certain modifications, allowing for recovery to begin in 2005. Recovery of these costs is dependent on pending settlement discussions.

Effective October 1, 2004, PJM began to assess a FERC-approved administrative fee on every megawatt consumed by DP&L customers. On October 26, 2004, DP&L filed an application with the PUCO for authority to modify its accounting procedures to defer collection of this PJM administrative fee, plus carrying charges, until such time as DP&L obtained the authority to adjust its rates to recover this cost from customers (i.e., after January 1, 2006). On June 1, 2005, the PUCO authorized DP&L to defer the PJM administrative fee, plus carrying charges incurred after the date of our application. On July 1, 2005, the OCC filed an Application for

Rehearing, which was subsequently denied by the PUCO, and on September 9, 2005 the case was appealed to the Ohio Supreme Court. On July 1, 2005, DP&L filed a subsequent case requesting PUCO authority for recovery of the PJM administrative fee from retail customers. On January 25, 2006, the PUCO issued an order approving the tariff as filed, which should result in approximately $8 million in additional revenue per year for three years beginning in February 2006. On February 13, 2006, the OCC filed an application for rehearing claiming the PUCO erred by not conducting a hearing and rejecting the OCC’s request for intervention. Commission action on the rehearing application is pending.

On July 23, 2003, the FERC issued an Order that the rates for transmission service of seven companies, including DP&L, may be unjust, unreasonable, or unduly discriminatory or preferential. DP&L is operating under FERC-approved rates through December 2008. In addition, the FERC ordered transitional payments, known as Seams Elimination Charge Adjustment (SECA), effective December 1, 2004 through March 31, 2006, subject to refund. Through this proceeding, we are obligated to pay SECA charges to other utilities but we receive a net benefit from these transitional payments. Several parties have sought rehearing of the FERC orders and there likely will be appeals filed in the matter. All motions for rehearing are pending. The hearing is scheduled to take place in May 2006. Beginning May 2005, DP&L began receiving these FERC ordered transitional payments and has received over $23 million of SECA collections, net of SECA charges, through December 2005. DP&L management believes that appropriate reserves have been established in the event that SECA collections are required to be refunded. The ultimate outcome of the proceeding establishing SECA rates is uncertain at this time. However, based on the amount of reserves established for this item, the results of this proceeding are not expected to have a material adverse effect on DP&L’s financial condition, results of operations or cash flows.

On May 31, 2005, the FERC instituted a proceeding under Federal Power Act Section 206 concerning the justness and reasonableness of PJM’s rate design. This proceeding sets the rates for hearing and requests that all of PJM members, which include DP&L, address the justness and reasonableness of the current rate design. On November 22, 2005, DP&L, along with ten other transmission owners, filed in support of PJM’s existing rate design. DP&L cannot determine what effect, if any, the outcome of this proceeding may have on its future recovery of transmission revenues. An April 18, 2006 hearing is scheduled in this case.

On August 8, 2005, the Energy Policy Act of 2005 (the 2005 Act) was enacted. This new law encompasses several areas including, but not limited to: electric reliability, repeal of the Public Utility Holding Company Act of 1935, promotion of energy infrastructure, preservation of a diverse fuel supply for electricity generation and energy efficiency. As a result of this legislation, the PUCO initiated an investigation to review their actions with respect to net metering, smart metering and demand response, cogeneration, and interconnection standards. The PUCO received comments on this proceeding and has established a series of technical conferences. At the conclusion of the conferences, parties will have an opportunity to provide additional comments by April 28, 2006. The PUCO could approve new regulatory requirements as a result of this proceeding. Also in response to the Energy Policy Act of 2005, on September 1, 2005, the FERC issued a Notice of Proposed Rulemaking to amend its regulations to incorporate the criteria any entity must satisfy to qualify to be an Electric Reliability Organization (ERO) that will propose and enforce reliability standards subject to FERC approval. The proposed rule also included related matters on delegating ERO authority, the creation of advisory bodies and reporting requirements. Other rulemakings are expected as a result

of the Energy Policy Act of 2005, such that DP&L cannot at this time measure the financial, operating and reporting impact of this new law.

On October 11, 2005, the FERC issued a proposed rulemaking relating to significant modifications to the FERC’s regulations on the Public Utility Regulatory Policies Act (PURPA). A final rule was issued on February 2, 2006 that supports the development of new cogeneration facilities that truly conserve energy. The new rules (1) assume new cogeneration facilities of 5 megawatts or less satisfy the requirement that the thermal output of the new cogeneration facility is used in a productive and beneficial manner; (2) ensure that there is continuing progress in the development of efficient electric energy generating technology and extend existing efficiency standards from gas and oil-fired qualified facilities to coal-fired qualifying facilities; (3) partially eliminate qualifying facility exemptions from regulation under the Federal Power Act; and (4) require that 50 percent of the annual energy output of the facility will be used for industrial, commercial, institutional or residential purposes and not sold to a utility. The impact of this rule change on DP&L is unclear at this time.

On March 3, 2005, DP&L received a notice that the FERC had instituted an operational audit of DP&L regarding its compliance with its Code of Conduct within the transmission and generation areas. On October 7, 2005, the FERC issued its Findings and Conclusions, stating that DP&L “generally complied with the FERC’s Standard of Conduct” with a few recommendations that were corrected to the satisfaction of the FERC prior to the issuance of their Findings and Conclusions.

On April 7, 2004, DP&L received notice that the staff of the PUCO was conducting an investigation into the financial condition of DP&L as a result of financial reporting and governance issues raised by the Memorandum. On May 27, 2004, the PUCO ordered DP&L to file a plan of utility financial integrity that outlines the actions the Company has taken or will take to insulate DP&L utility operations and customers from its unregulated activities. DP&L was required to file this plan by March 2, 2005. On February 4, 2005, DP&L filed its protection plan with the PUCO and expressed its intention to continue to cooperate with the PUCO in their investigation. On March 29, 2005, the OCC filed comments with the PUCO on DP&L’s financial plan of integrity, requesting the PUCO continue the investigation and monitor DP&L’s progress toward implementation of its financial plan of integrity. On June 29, 2005, the PUCO closed its investigation, citing significant positive actions taken by DP&L including changes in the Board of Directors as well as executive management of DP&L, and that no apparent diminution of service quality has occurred because of the events that initiated the investigation.

On August 2, 2004, in order to strengthen MVIC’s financial position, the Vermont Department of Banking, Insurance, Securities and Health Care Administration notified MVIC of MVIC’s requirement to reduce its intercompany receivable to a maximum no greater than MVIC’s total capital and surplus plus $250,000 minimum capital. As a result, we transferred $5 million from our operating cash to our subsidiary, MVIC, in satisfaction of this requirement during the fourth quarter of 2004. In January 2005, MVE transferred a private equity financial asset valued in excess of $31.5 million to MVIC to further strengthen MVIC’s financial position. During 2005 the private equity financial assets owned by MVIC were sold along with the rest of the private equity funds. MVIC distributed dividends to DPL from the proceeds of these sales. During the review of the second quarter financial statements, we noted that these transactions inadvertently caused the shareholder equity of MVIC to fall below the required level. In discussions with the Vermont Department of Banking, Insurance, Securities and Health Care Administration it was decided that we would maintain a loss reserve to shareholder equity ratio of 3:1 in MVIC. As a result, during the third quarter of 2005 we transferred $12.3 million from our operating cash to MVIC in satisfaction of this new requirement.

CONSTRUCTION ADDITIONS

Construction additions were $180 million, $98 million and $102 million in 2005, 2004 and 2003, respectively, and are expected to approximate $365 million in 2006. Planned construction additions

for 2006 relate to DP&L’s environmental compliance program, power plant equipment, and its 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. Over the next three years, we are projecting to spend an estimated $750 million in capital projects, approximately 60% of which is to meet changing environmental 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, and adequate and timely return on these capital investments. We expect to finance our construction additions in 2006 with a combination of cash and short-term investments on hand, tax-exempt debt and internally-generated funds.

See ENVIRONMENTAL CONSIDERATIONS for a description of environmental control projects and regulatory proceedings that may change the level of future construction additions. The potential effect of these events on our operations cannot be estimated at this time.

ELECTRIC OPERATIONS AND FUEL SUPPLY

Our present summer generating capacity – including Peaking Units — is approximately 4,405 MW. Of this capacity, approximately 2,856 MW or 65% is derived from coal-fired steam generating stations and the balance of approximately 1,549 MW or 35% consists of combustion turbine and diesel peaking units. Combustion turbine output is dependent on ambient conditions and is higher in the winter than in the summer. Our all-time net peak load was 3,243 MW, occurring July 25, 2005.

Approximately 87% of the existing steam generating capacity is provided by certain units owned as tenants in common with The Cincinnati Gas & Electric Company (CG&E) or its subsidiary, Union Heat, Light & Power, and Columbus Southern Power Company (CSP). As tenants in common, each company owns a specified undivided 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. DP&L’s remaining steam generating capacity (approximately 365 MW) is derived from a generating station owned solely by DP&L. Additionally, DP&L, CG&E and CSP own as tenants in common, 884 circuit miles of 345,000-volt transmission lines. DP&L has several interconnections with other companies for the purchase, sale and interchange of electricity.

In 2005, we generated 99% of our electric output from coal-fired units and 1% from oil or natural gas-fired units.

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

Approximate Summer

Operating

MW Rating

Station

Ownership*

Company

Location

DPL Portion

Total

Coal Units

Hutchings

DP&L

Miamisburg, OH

365

Killen

DP&L

Wrightsville, OH

412

615

Stuart

DP&L

Aberdeen, OH

832

2,376

Conesville-Unit 4

CSP

Conesville, OH

129

780

Beckjord-Unit 6

CG&E

New Richmond, OH

207

414

Miami Fort-Units 7 & 8

CG&E

North Bend, OH

360

1,000

East Bend-Unit 2

CG&E

Rabbit Hash, KY

186

600

Zimmer

CG&E

Moscow, OH

365

1,300

Combustion Turbines or Diesel

Hutchings

DP&L

Miamisburg, OH

Yankee Street

DP&L

Centerville, OH

107

Monument

DP&L

Dayton, OH

Tait Diesels

DP&L

Dayton, OH

Sidney

DP&L

Sidney, OH

Tait Units 1-3

DP&L

Moraine, OH

256

Killen

DP&L

Wrightsville, OH

Stuart

DP&L

Aberdeen, OH

Greenville Units 1-4

DPLE

Greenville, OH

192

Darby Station Units 1-6

DPLE

Darby, OH

438

Montpelier Units 1-4

DPLE

Montpelier, IN

192

Tait Units 4-7

DPLE

Moraine, OH

292

Total approximate summer generating capacity

4,405

9,012

*W = Wholly-Owned

C = Commonly-Owned

We have approximately 95% of the total expected coal volume needed for 2006 under contract. The percentage of coal under contract at our individual facilities is as low as 80%. Contracted coal volumes at certain facilities exceed 100% of the expected need. Due to the differences in contracted volumes at various facilities, it is expected we will be in the spot market for more than 5% of our 2006 coal volume at some facilities while we may make no spot purchases at other facilities. We may have excess coal volumes to meet 2007 needs at some facilities. The majority of our contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustment and some are priced based on market indices. Substantially all contracts have features that limit price escalations in any given year. Our 2006 emission allowance (SO2) consumption is expected to be similar to 2005. Our holdings of 2006 SO2 allowances are approximately equal to its expected needs. There may be small exchanges of allowances between 2006 and future years to balance our 2006 position. We do not expect to purchase allowances outright for 2006. The exact consumption of SO2 allowances will depend on market prices for power, availability of our generating units and the actual sulfur content of the coal burned.

The average cost of fuel used per kilowatt-hour (kWh) generated was 1.93¢ in 2005, 1.56¢ in 2004 and 1.33¢ in 2003.

SEASONALITY

The power generation and delivery business is seasonal and weather patterns have a material impact on operating performance. In the region served by our subsidiaries, demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating as compared to other times of the year. Historically, the power generation and delivery operations of our subsidiaries have generated less revenue and income when weather conditions are warmer in the winter and cooler in the summer.

RATE REGULATION AND GOVERNMENT LEGISLATION

DP&L’s sales to retail customers are subject to rate regulation by the PUCO. DP&L’s wholesale electric rates to municipal corporations 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 rates charged by public utilities. Regulation of rates encompasses the timing of applications, the effective date of rate increases, the cost basis upon which the rates are based and other related matters. Ohio law also established the Office of the Ohio Consumers’ Counsel (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 they relate to the costs associated with the provision of public utility service. Based on

existing PUCO authorization, regulatory assets and liabilities are recorded on the Consolidated Balance Sheets. (See Note 3 of Notes to Consolidated Financial Statements.)

See COMPETITION AND REGULATION for more detail regarding the effect of legislation.

ENVIRONMENTAL CONSIDERATIONS

The operations of DPL and DP&L, including DP&L’s commonly-owned facilities, are subject to a wide range of federal, state, and local environmental regulations and laws as to air and water quality, disposal of solid waste and other environmental matters. Governance also includes the location, construction and operation of new and existing electric generating facilities and most electric transmission lines. As such, existing environmental regulations may be periodically revised and new legislation could be enacted that may affect our estimated construction expenditures. See CONSTRUCTION ADDITIONS. In the normal course of business, DP&L has ongoing programs and activities underway at these facilities to comply, or to determine compliance, with such existing, new and/or proposed regulations and legislation.

DP&L has been identified, either by a government agency or by a private party seeking contribution to site clean-up costs, as a potentially responsible party (PRP) at two sites pursuant to state and federal laws. DP&L records liabilities for probable estimated loss in accordance with Statement of Financial Accounting Standards No. 5 (SFAS 5), “Accounting for Contingencies.” To the extent a probable loss can only be estimated by reference to a range of equally probable outcomes, and no amount within the range appears to be a better estimate than any other amount, DP&L accrues for the low end of the range. Because of uncertainties related to these matters, accruals are based on the best information available at the time. DP&L evaluates the potential liability related to probable losses quarterly and may revise its estimates. Such revisions in the estimates of the potential liabilities could have a material effect on the Company’s results of operations and financial position.

Air and Water Quality

In November 1999, the United States Environmental Protection Agency (USEPA) filed civil complaints and Notices of Violations (NOVs) against operators and owners of certain generation facilities for alleged violations of the Clean Air Act (CAA). Generation units operated by CG&E (Beckjord 6) and Columbus Southern Power Company (CSP) (Conesville 4) and co-owned by DP&L were referenced in these actions. Numerous northeast states have filed complaints or have indicated that they will be joining the USEPA’s action against CG&E and CSP. DP&L was not identified in the NOVs, civil complaints or state actions.

On March 1, 2000, the United States Department of Justice filed a complaint against Cinergy Corporation and two subsidiaries (USA v. Cinergy Corp. et al) for alleged violations of the CAA at various generation units operated by PSI Energy, Inc. and CG&E. The complaint was amended June 24, 2004 and includes generation units operated by CG&E and co-owned by DP&L (Beckjord 6 and Miami Fort 7). The suit seeks (1) injunctive relief to require installation of pollution control technology on various generating units at CG&E’s W.C. Beckjord and Miami Fort Stations, and PSI’s Cayuga, Gallagher, Wabash River, and Gibson Stations, and (2) civil penalties in amounts of up to $27,500 per day for each violation. In addition, three northeast states and two environmental groups have intervened in the case. In August 2005, the district court issued a ruling regarding the emissions test that it will apply to Cinergy at the trial of the case. Contrary to Cinergy’s argument, the district court ruled that in determining whether a project was projected to increase annual emissions, it would not hold hours of operation constant. However, the district court subsequently certified the matter for interlocutory appeal to the Seventh Circuit Court of Appeals, which has the discretion to accept the appeal at this time. Oral arguments have been scheduled for May 29, 2006.

In June 2000, the USEPA issued a NOV to DP&L-operated Stuart Generating Station (co-owned by DP&L, CG&E, and CSP) for alleged violations of the CAA. The NOV contained allegations consistent with NOVs and complaints that the USEPA had recently brought against numerous other coal-fired utilities

in the Midwest. The NOV indicated EPA 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.

On September 21, 2004, the Sierra Club filed a lawsuit against the Company and the other owners of the Stuart Generating Station in the United States District Court for the Southern District of Ohio for alleged violations of the CAA. The case is currently in discovery; a trial date has not been set.

On July 27, 2004, various residents of the Village of Moscow, Ohio notified CG&E, as the operator of Zimmer (co-owned by CG&E, DP&L and CSP), of their intent to sue for alleged violations of the CAA and air pollution nuisances. On November 17, 2004, a citizens’ suit was filed against CG&E (Freeman v. CG&E). DP&L believes the allegations are meritless and believes CG&E, on behalf of all co-owners, will vigorously defend the matter. The plaintiffs have filed a number of additional notices of intent to sue and two lawsuits raising claims similar to those in the original claim. One lawsuit was dismissed on procedural grounds and the remaining two have been consolidated. The plaintiffs have filed for class action status; a decision has not yet been reached on this matter.

On November 18, 2004, the State of New York and seven other states filed suit against the American Electric Power Corporation (AEP) and various subsidiaries, alleging various CAA violations at a number of AEP electric generating facilities, including Conesville Unit 4 (co-owned by CG&E, DP&L and CSP). DP&L believes the allegations are without merit and that AEP, on behalf of all co-owners, will vigorously defend the matter. On January 6, 2006, the court ordered the consolidation of this case with another similar suit; a trial date for the remedy phase of the consolidated cases has not yet been set.

On October 27, 2003, the USEPA published its final rules regarding the equipment replacement provision (ERP) of the routine maintenance, repair and replacement (RMRR) exclusion of the CAA. Subsequently, on December 24, 2003, the United States Court of Appeals for the D.C. Circuit stayed the effective date of the rule pending its decision on the merits of the lawsuits filed by numerous states and environmental organizations challenging the final rules. As a result of the stay, the Ohio Environmental Protection Agency (Ohio EPA) delayed its previously announced intent to adopt the RMRR rule. On October 20, 2005, USEPA proposed to revise the emissions test for existing electric generating units. At this time, we are unable to determine the impact of the ERP appeal or the outcome of the proposed emission test.

In September 1998, the USEPA issued a final rule requiring states to modify their State Implementation Plans (SIPs) under the CAA. On July 18, 2002, the Ohio EPA adopted rules that constitute Ohio’s NOx SIP, which is substantially similar to the federal CAA Section 126 rulemaking and federal NOx SIP. On August 5, 2003, the USEPA published its conditional approval of Ohio’s nitrogen oxide (NOx) SIP, with an effective date of September 4, 2003. Ohio’s SIP requires NOx reductions at coal-fired generating units effective May 31, 2004. On May 31, 2004, DP&L began operation of its Selective Catalytic Reduction equipment (SCRs). DP&L’s NOx reduction strategy and incurred expenditures to meet the federal reduction requirements should satisfy the Ohio SIP NOx reduction requirements.

On December 17, 2003, the USEPA proposed the Interstate Air Quality Rule (IAQR) designed to reduce and permanently cap sulfur dioxide (SO₂) and NOx emissions from electric utilities. The proposed IAQR focused on states, including Ohio, whose power plant emissions are believed to be significantly contributing to fine particle and ozone pollution in other downwind states in the eastern United States. On June 10, 2004, the USEPA issued a supplemental proposal to the IAQR, now renamed as the Clean Air Interstate Rule (CAIR). The final rules were signed on March 10, 2005 and were published on May 12, 2005. On August 24, 2005, the USEPA proposed additional revisions to the CAIR and initiated reconsideration on one issue. Although we cannot predict the outcome of the

reconsideration proceedings, the petitions or pending litigation, CAIR has had and will have a material effect on our operations. We anticipate that Phase I of CAIR will require the installation of flue gas desulphurization (FGD) equipment and continual operation of the currently-installed SCR. As a result, DP&L is proceeding with the installation of FGD equipment at various generating units.

On January 30, 2004, the USEPA published its proposal to restrict mercury and other air toxics from coal-fired and oil-fired utility plants. The final Clean Air Mercury Rule (CAM-R) was signed March 15, 2005 and was published on May 18, 2005. The final rules will have a material effect on our operations. We anticipate that the FGD being planned to meet the requirements of CAIR may be adequate to meet the Phase I requirements of CAM-R. We expect that additional controls will be needed to meet the Phase II requirements of CAM-R that go into effect January 1, 2018. On March 29, 2005, nine states sued USEPA, opposing the regulatory approach taken by USEPA. On March 31, 2005, various groups requested that USEPA stay implementation of CAM-R. On August 4, 2005, the United States Court of Appeals for the District of Columbia denied the motion for stay. EPA is expected to initiate reconsideration proceedings on one or more issues. We cannot predict the outcome of the reconsideration proceedings or pending litigation.

Under the CAIR and CAM-R cap and trade programs for SO_2,NOx and mercury, we estimate we will spend more than $453 million from 2006 through 2008 to install the necessary pollution controls. If CAM-R litigation results in plant specific mercury controls, our costs may be higher. Due to the ongoing uncertainties associated with the litigation of the CAM-R, we cannot project the final costs at this time.

On July 15, 2003, the Ohio EPA submitted to the USEPA its recommendations for eight-hour ozone nonattainment boundaries for the metropolitan areas within Ohio. On April 15, 2004, the USEPA issued its list of ozone nonattainment designations. DP&L owns and/or operates a number of facilities in counties designated as nonattainment with the ozone national ambient air quality standard. DP&L does not know at this time what future regulations may be imposed on its facilities and will closely monitor the regulatory process. Ohio EPA will have until April 15, 2007 to develop regulations to attain and maintain compliance with the eight-hour ozone national ambient air quality standard. Numerous parties have filed petitions for review. DP&L cannot predict the outcome of USEPA’s reconsideration petitions.

On January 5, 2005, the USEPA published its final nonattainment designations for the national ambient air quality standard for Fine Particulate Matter 2.5 (PM 2.5) designations. These designations included counties and partial counties in which DP&L operates and/or owns generating facilities. On March 4, 2005, DP&L and other Ohio electric utilities and electric generators filed a petition for review in the D.C. Circuit Court of Appeals, challenging the final rule creating these designations. On November 30, 2005, the court ordered USEPA to decide on all petitions for reconsideration by January 20, 2006. On January 20, 2006, USEPA denied the petitions for reconsideration. The Ohio EPA will have three years to develop regulations to attain and maintain compliance with the PM 2.5 national ambient air quality standard. DP&L cannot determine the outcome of the petition for review or the effect such Ohio EPA regulations will have on its operations.

In April 2002, the USEPA issued proposed rules governing existing facilities that have cooling water intake structures. Final rules were published in the Federal Register on July 9, 2004. A number of parties appealed the rules to the federal Court of Appeals for the Second Circuit in New York. The Company anticipates that future studies may be needed at certain generating facilities. We cannot predict the impact such studies may have on future operations or the outcome of litigation proceedings.

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. In the final rule, USEPA made

the determination that CAIR achieves greater progress than BART and may be used by States as a BART substitute. Numerous units owned and operated by us will be impacted by BART. We cannot determine the extent of the impact until Ohio determines how BART will be implemented.

On May 4, 2004, the Ohio EPA issued a final National Pollutant Discharge Elimination System permit for J.M. Stuart Station that continues the station��s 316(a) variance. During the three-year term of the draft permit, DP&L will conduct a thermal discharge study to evaluate the technical feasibility and economic reasonableness of water cooling methods other than cooling towers.

On October 13, 2005, the USEPA issued a proposed rule concerning the test for measuring whether modifications to electric generating units should trigger application of New Source Review (NSR) standards under the CAA. The proposed rule seeks comments on two different hourly emissions test options as well as the USEPA’s current method of measuring previous actual emission levels to projected actual emission levels after the modification. A third option that tests emissions increase based upon emissions per unit of energy output is also available for comment. We cannot predict the outcome of this rulemaking or its impact on current environmental litigation.

Land Use

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be PRPs for the clean-up of hazardous substances at the South Dayton Dump landfill site. On August 4, 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. On October 5, 2005, DP&L received a special notice letter inviting it to enter into negotiations with USEPA to conduct the RI/FS. Although the information available to DP&L does not demonstrate that it contributed hazardous substances to the site, DP&L will seek from USEPA a de minimis settlement at the site. Should USEPA pursue a civil action, DP&L will vigorously challenge it.

DPL INC.

OPERATING STATISTICS

ELECTRIC OPERATIONS

	Years Ended December 31,
	2005		2004		2003
Electric Sales (millions of kWh)
Residential	5,520		5,140		5,071
Commercial	3,901		3,777		3,699
Industrial	4,332		4,393		4,330
Other retail	1,437		1,407		1,409
Total retail	15,190		14,717		14,509

Wholesale	2,716		3,748		4,836

Total	17,906		18,465		19,345

Operating Revenues ($ in thousands)
Residential	$	478,226	$	449,411	$	442,239
Commercial	276,157		267,831		264,067
Industrial	220,453		223,335		221,961
Other retail	81,716		80,370		80,583
Other miscellaneous revenues	10,069		15,863		12,895
Total retail	1,066,621		1,036,810		1,021,745

Wholesale	133,283		135,129		159,250

RTO ancillary revenues	74,419		17,905		—

Other revenues, net of fuel costs	10,586		10,054		9,970

Total	$	1,284,909	$	1,199,898	$	1,190,965

Electric Customers at End of Period
Residential	456,146		453,653		450,958
Commercial	48,853		48,172		47,253
Industrial	1,837		1,851		1,863
Other	6,304		6,337		6,322

Total	513,140		510,013		506,396

Item 1a – Risk Factors

This annual report and other documents that we file with the SEC and other regulatory agencies, as well as other oral or written statements we may make from time to time, contain information based on management’s beliefs and include forward-looking statements (within the meaning of the Private Securities Litigation Reform Act of 1995) that involve a number of known and unknown risks, uncertainties and assumptions. These forward-looking statements are not guarantees of future performance, and there are a number of factors including, but not limited to, those listed below, which could cause actual outcomes and results to differ materially from the results contemplated by such forward-looking statements. We do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. These forward-looking statements are identified by terms and phrases such as “anticipate”, “believe”, “intend”, “estimate”, “expect”, “continue”, “should”, “could”, “may”, “plan”, “project”, “predict”, “will”, and similar expressions.

The following is a listing of risk factors that we consider to be the most significant to your decision to invest in our stock. If any of these events occurs, our business, financial position or results of operation could be materially affected.

Our stock price may fluctuate

The market price of our common stock has fluctuated over a wide range. In addition, the stock market in recent years has experienced significant price and volume variations that have often been unrelated to our operating performance. Over the past three years, the market price of our common stock has fluctuated with a low of $11.95 and a high of $28.12. The market price of our common stock may continue to fluctuate in the future and may be affected adversely by factors such as actual or anticipated changes in our operating results, acquisition activity, changes in financial estimates by securities analysts, general market conditions, rumors and other factors.

The electric industry in Ohio is partially deregulated

Before 2001, electric utilities provided electric generation, transmission and distribution services as a single product to retail customers at prices set by The Public Utilities Commission of Ohio (PUCO). But in 1999, Ohio enacted legislation, effective January 1, 2001, that partially deregulated utility service, making retail generation service a competitive service. Customers may choose to take generation service from competitive retail electric service (CRES) providers that register with the PUCO but are otherwise unregulated. In connection with this partial deregulation of the electric

industry in Ohio, electric utilities have had to restructure their service and their rates to accommodate competition.

Many of the requirements of the Ohio deregulation law were premised on the assumption that the wholesale generation market and, in turn, the retail generation market, would fully develop by the end of 2005, and that the price for generation for even those customers who choose to continue to purchase the service from the regulated utility would be set purely by the market. But that did not occur. As a result, the Commission and the utilities, including DP&L, have worked out plans to provide market-based pricing for generation service, but also to stabilize those rates for several years. What DP&L may propose, and what the PUCO will approve, in the future regarding pricing and cost recovery will depend on the degree to which the wholesale and retail electric generation markets have developed.

Moreover, the uncertainty of the future of the wholesale and retail markets could cause the Ohio General Assembly to revisit the issue of competition and customer choice.

Although there has not yet been significant switching by DP&L’s customers to CRES providers, that could occur in the future.

Although retail generation service has been a competitive service since January 1, 2001, the competitive generation market has not developed in DP&L’s service territory to any significant degree. But there are factors that could result in increased switching by customers to CRES providers in the future:

• Voluntary Enrollment Procedure

As part of a settlement in a PUCO proceeding, DP&L initiated, in November 2004, a voluntary enrollment procedure (VEP) to encourage customers to change electric suppliers. Although the VEP did not result in a significant increase in the number of customers switching to CRES providers, the VEP will be initiated again in 2006 and 2007 and could produce different results.

• CRES Supplier Initiatives

Even without the VEP, customers can elect to take generation service from a competitive retail electric service (CRES) provider. As of December 31, 2005, five CRES providers have been certified by the PUCO to provide generation service in DP&L’s service territory. One of those five, DPL Energy Resources, Inc. (DPLER), is an affiliate of DP&L. Although DPLER has accounted for nearly all of the load served by CRES providers in DP&L’s service territory since retail competition began in 2001, that could change. Depending on the development of the wholesale market and the level of wholesale prices, CRES providers could become more active in DP&L’s service territory and could begin to offer better prices than they do now. This could result in more switching by DP&L’s customers and a further loss by DP&L of its generation business.

• Governmental Aggregation Programs

Another possible way in which DP&L could lose generation customers is through “governmental aggregation,” which was permitted in the restructuring legislation. Under this program, municipalities may contract with a CRES provider to provide generation service to the customers located within the municipal boundaries. Several communities in DP&L’s service territory have passed ordinances allowing them to become government aggregators. Although none has yet implemented an aggregation program, that too, could change if CRES providers are able to make lower-priced offers as a result of decreasing prices in the wholesale market.

DP&L’s ability to increase its rate to recover increased costs is limited.

As a result of the failure of the market to develop as anticipated, DP&L has proposed to stabilize its market-based generation rates rather than subject customers to the volatile rates that would otherwise be applicable in the absence of the rate stabilization plan. DP&L’s distribution rates will be unchanged through December 31, 2008 and its generation rates will be maintained through December 31, 2008. Although the PUCO has approved several riders that will permit DP&L to offset increases in fuel and environmental costs, the environmental rider is not payable by customers that take generation service from a CRES provider. Thus, a significant migration of customers from DP&L’s generation service to CRES providers could affect DP&L’s ability to recover those costs. Moreover, DP&L will not be able to adjust its rates during the rate stabilization period for increases in other expenses or to recover capital expenditures.

DP&L has agreed to provide service at pre-determined rates through December 31, 2010, which limits its ability to pass through its costs to customers.

DP&L has provided service at rates governed by the PUCO-approved transition, market development, and rate stabilization plans. Those rates have included a statutorily-required 5% residential rate reduction in the generation component of its rates, a further 2.5% reduction to the residential generation rate, with its generation rates frozen through December 31, 2010, and guaranteed distribution rates through December 31, 2008. The protection afforded by retail fuel clause recovery mechanisms was eliminated effective January 1, 2001 by the implementation of customer choice in Ohio. The RSS Stipulation (as defined above), although subject to judicial review, extends DP&L’s commitment to maintain pre-determined rates for distribution through December 31, 2008, with limited ability to recover certain costs after December 31, 2005. Likewise, through the RSS Stipulation, DP&L extended its commitment to maintain pre-determined rates for generation through December 31, 2010, and in exchange is permitted to charge two new rate riders to offset increases in fuel and environmental costs. Beginning January 1, 2006 a new Rate Stabilization Surcharge was implemented that should recover approximately $60 to $65 million additional revenue in 2006, net of customer discounts and considering less than a full twelve months recovery due to the timing of the PUCO order. The new environmental investment rider could result in approximately $35 million additional revenue in 2007, net of customer discounts and assuming no customer switching. The PUCO ruled this rider will be bypassable by all customers who take service from alternative generation suppliers. Accordingly, the rates DP&L is allowed to charge may or may not match its expenses at any given time. Therefore, during this period (or possibly earlier by order of the PUCO), and, thereafter, while DP&L will be subject to prevailing market prices for electricity, it would not necessarily be able to charge rates that produce timely or full recovery of its expenses. DP&L has historically maintained its rates at consistent levels since 1994, when the last phase of DP&L’s last traditional rate case was implemented. However, as DP&L operates under its PUCO-approved RSS Stipulation, there can be no assurance that DP&L would be able to timely or fully recover unanticipated levels of expenses, including but not limited to those relating to fuel, coal and purchased power, compliance with environmental regulation, reliability initiatives, and capital expenditures for the maintenance or repair of its plants or other properties.

There are uncertainties relating to the ultimate development of Regional Transmission Organizations (RTOs), including the PJM to which DP&L has given control of its transmission functions.

On October 1, 2004, DP&L gave PJM control of its transmission functions and fully integrated into PJM. Problems or delays that may arise in the operation of RTOs may restrict DP&L’s ability to sell power produced by its generating capacity to certain markets if there is insufficient transmission capacity otherwise available. The rules governing the various regional power markets may also change from time to time which could affect DP&L’s costs and revenues. While RTO rates are designed to be revenue neutral, DP&L’s revenues from customers to whom they currently provide transmission services could decrease. DP&L will incur fees and increased costs to participate in an RTO, it may be limited with respect to the price at which power may be offered for sale from certain generating units, and it may be required to expand its transmission system according to decisions

made by an RTO rather than its internal planning process. Because the RTO market rules are continuing to evolve, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have on DP&L and us.

We rely principally on coal as the fuel to operate virtually all of the power plants that serve our customers daily. We are dependant on our coal suppliers to continually supply our power plants to avoid an interruption in our generation of electricity.

Some of our coal suppliers have not performed their contracts as promised and have failed to timely deliver all coal as specified under their contracts. Such failure could significantly reduce DP&L’s inventory of coal and may cause DP&L to purchase higher priced coal on the spot market. When the failure is for a short period of time, DP&L can absorb the irregularity due to existing inventory levels. If we are required to purchase coal on the spot market, it may affect our cost of operations.

There are additional factors, including, but not limited to, regulation and competition, economic conditions, reliance on third parties, operating results fluctuations, regulatory uncertainties and litigation, warrant exercise, internal controls and environmental compliance, that may affect our future results.

Regulation/Competition

We operate in a rapidly changing industry with evolving industry standards and regulations. In recent years a number of federal and state developments aimed at promoting competition triggered industry restructuring. Regulatory factors, such as changes in the policies and procedures that set rates; changes in tax laws, tax rates, and environmental laws and regulations; changes in DP&L’s ability to recover expenditures for environmental compliance, fuel and purchased power costs and investments made under traditional regulation through rates; and changes to the frequency and timing of rate increases can affect our results of operations and financial condition. Changes in our customer base, including municipal customer aggregation, could lead to the entrance of competitors in our marketplace, affecting our results of operations and financial condition. Additionally, financial or regulatory accounting principles or policies imposed by governing bodies can increase our operational and monitoring costs affecting our results of operations and financial condition.

Economic Conditions

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.

On October 8, 2005, Delphi Corporation filed for Chapter 11 bankruptcy protection in the U.S. Bankruptcy Court for the Southern District of New York. Delphi represents approximately 1% of our annual revenues.

During the past few years, the merchant energy industry in many parts of the United States has suffered from oversupply of merchant generation and a decline in trading and marketing activity. These market conditions are expected to continue for several years. As a result of these market conditions, we continue to evaluate the carrying values of certain long-lived generation assets.

Reliance on Third Parties

We rely on many suppliers for the purchase and delivery of inventory, including coal, and equipment components to operate our energy production, transmission and distribution functions. Unanticipated changes in our purchasing processes, delays and supplier availability may affect our business and operating results. In addition, we rely on others to provide professional services, such as, but not limited to, actuarial calculations, internal audit services, payroll processing and various consulting services.

Operating Results Fluctuations

Future operating results are subject to fluctuations based on a variety of factors, including but not limited to: unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages; unusual maintenance or repairs; changes in coal costs, gas supply costs, emissions allowance costs, or availability constraints; environmental compliance; and electric transmission system constraints.

Regulatory Uncertainties and Litigation

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. Additionally, we are subject to diverse and complex laws and regulations, including those relating to corporate governance, public disclosure and reporting, and taxation, which are rapidly changing and subject to additional changes in the future. As further described in Item 3 - "Legal Proceedings," we are also currently involved in various pieces of litigation in which the outcome is uncertain. Compliance with these rapid changes may substantially increase costs to our organization and could affect our future operating results.

Warrant Exercise

Our warrant holders could exercise their 31,560,000 warrants at their discretion until March 12, 2012. As a result, we could be required to issue up to 31,560,000 common shares in exchange for the receipt of the exercise price of $21.00 per share or pursuant to a cashless exercise process. The exercise of all warrants could have a significant dilutive effect on us and would increase our common share dividend cost and may affect any existing guidance on basic earnings per share.

Internal Controls

Our internal controls, accounting policies and practices, and internal information systems are designed to enable us to capture and process transactions in a timely and accurate manner in compliance with accounting principles generally accepted in the United States of America (GAAP), laws and regulations, taxation requirements, and federal securities laws and regulations. We implemented corporate governance, internal control and accounting rules issued 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 to ensure continued compliance with Section 404 of the Act. 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 impact our financial condition, cash flows or results of operations.

Environmental Compliance

Our generating facilities (both wholly-owned and co-owned with others) are subject to continuing federal and state environmental laws and regulations. We believe that we currently comply with all existing federal and state environmental laws and regulations. We own a non-controlling, minority interest in several generating stations operated by The Cincinnati Gas & Electric Company (CG&E) or its affiliate, Union Heat, Light & Power, and Columbus Southern Power Company (CSP). Either or both of these parties are likely to take steps to ensure that these stations remain in compliance with applicable environmental laws and regulations. As non-controlling owners in these generating stations, we will be responsible for our pro rata share of these expenditures based upon our ownership interest.

Item 1b – Unresolved Staff Comments

None

Item 2 - Properties

Electric

Information relating to our properties is contained in Item 1 – CONSTRUCTION ADDITIONS, and ELECTRIC OPERATIONS AND FUEL SUPPLY, and Note 10 of Notes to Consolidated Financial Statements.

Substantially all property and plant of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage, dated as of October 1, 1935 with the Bank of New York, as Trustee (Mortgage).

Item 3 - Legal Proceedings

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our consolidated financial statements, as prescribed by GAAP, for these matters are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts may be required to satisfy alleged liabilities from various legal proceedings, claims, and other matters discussed below, and to comply with applicable laws and regulations will not exceed the amounts reflected in our Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2005, cannot be reasonably determined.

On August 24, 2004, we, and our subsidiaries DP&L and MVE, filed a Complaint against Mr. Forster, Ms. Muhlenkamp and Mr. Koziar (the Defendants) in the Court of Common Pleas of Montgomery County, Ohio asserting legal claims against them relating to the termination of the Valley Partners Agreements, challenging the validity of the purported amendments to the deferred compensation plans and to the employment and consulting agreements with the Defendants, and the propriety of the distributions from the plans to the Defendants, and alleging that the Defendants breached their fiduciary duties and breached their consulting and employment contracts. We, DP&L and MVE seek, among other things, damages in excess of $25,000, disgorgement of all amounts improperly withdrawn by the Defendants from the plans and a court order declaring that we, DP&L and MVE have no further obligations under the consulting and employment contracts due to those breaches.

The Defendants filed motions to dismiss the Complaint, which the Court subsequently denied. On June 15, 2005, Defendants filed their answers denying liability and filed counterclaims against us, DP&L, MVE, various compensation plans (the Plans), and against the then-current members of our Board of Directors and two of our former Board members. These counterclaims allege generally that DPL, DP&L, MVE, the Plans and the individual defendants breached the terms of the employment and consulting contracts of the Defendants, and the terms of the Plans. They further allege theories of breach of fiduciary duty, breach of contract, promissory estoppel, tortious interference, conversion, replevin and violations of ERISA under which they seek distribution of deferred compensation balances, conversion of stock incentive units, exercise of options and payment of amounts allegedly owed under the contracts and the Plans. Defendants’ counterclaims also demand payment of attorneys’ fees. Motions to dismiss certain of the counterclaims were denied on February 23, 2006.

We, DP&L and MVE filed a Motion for Preliminary Injunction in the Ohio case, requesting that the court issue a preliminary injunction against Mr. Forster and Ms. Muhlenkamp regarding the New York lawsuit. On August 18, 2005, the Ohio court issued a preliminary injunction against Mr. Forster and Ms. Muhlenkamp that precludes them from pursuing certain key issues raised by Mr. Forster and Ms. Muhlenkamp in their New York lawsuit that are identical to the issues raised in the pending Ohio lawsuit in the New York court or any other forum other than the Ohio litigation. In addition, the New York court has stayed the New York litigation pending the outcome of the Ohio litigation. Mr. Forster and Ms. Muhlenkamp have appealed the preliminary injunction and the appeal is pending at the Ohio Supreme Court.

The parties continue to proceed with the discovery phase of the litigation, and a number of motions have been filed and briefed with respect to document discovery and depositions. The trial court granted some and overruled some of these pending motions on February 23, 2006.

We continue to evaluate all of the matters relevant to this litigation and are considering other claims against Defendants, Forster, Muhlenkamp and Koziar that include, but are not limited to, breach of fiduciary duty or other claims relating to personal and DPL investments, the calculation of benefits under the Supplemental Executive Retirement Program (SERP) and financial reporting with respect to such benefits, and with respect to Mr. Koziar, the fulfillment of duties owed to us as our legal counsel. Cumulatively through December 31, 2005, we have accrued for accounting purposes, obligations of approximately $52 million to reflect claims regarding deferred compensation, estimated MVE incentives and/or legal fees that Defendants assert are payable per contracts. We dispute Defendants’ entitlement to any of those sums and, as noted above, are pursuing litigation against them contesting all such claims.

On or about June 24, 2004, the SEC commenced a formal investigation into the issues raised by the Memorandum. We are cooperating with the investigation.

On April 7, 2004, the Company received notice that the staff of the PUCO was conducting an investigation into the financial condition of DP&L as a result of the issues raised by the Memorandum. On May 27, 2004, the PUCO ordered DP&L to file a plan of utility financial integrity that outlines the actions the Company has taken or will take to insulate DP&L utility operations and customers from its unregulated activities. DP&L was required to file this plan by March 2, 2005. On February 4, 2005, DP&L filed its protection plan with the PUCO. On June 29, 2005, the PUCO closed its investigation, citing significant positive actions we had taken including changes in the Board of Directors as well as the executive management of DP&L, and that no apparent diminution of service quality had occurred because of the events that initiated the investigation.

On May 20, 2004, the staff of the SEC notified us that it was conducting an inquiry covering our exempt status under the Public Utility Holding Company Act of 1935 (the ‘35 Act). The staff of the SEC requested we provide certain documents and information on a voluntary basis. On October 8, 2004, we received a notice from the SEC that a question exists as to whether such exemption from the Public Utility Holding Company Act may be detrimental to the public interest or the interests of investors or consumers. On November 5, 2004, we filed a good faith application seeking an order of exemption from the SEC. In light of the repeal of the ‘35 Act, effective February 8, 2006, and based upon the information previously provided to the staff of the SEC, this inquiry is moot.

On May 28, 2004, the U.S. Attorney’s Office for the Southern District of Ohio, assisted by the Federal Bureau of Investigation, notified us that it has initiated an inquiry involving the subject matters covered by our internal investigation. We are cooperating with this investigation.

On June 24, 2004, the Internal Revenue Service (IRS) began an audit of tax years 1998 through 2003 and issued a series of data requests to us including issues raised in the Memorandum. The staff of the IRS has requested that we provide certain documents, including but not limited to, matters concerning executive/director deferred compensation plans, management stock incentive plans and MVE financial statements. On September 1, 2005, the IRS issued an audit report for tax years 1998 through 2003 that shows proposed changes to our federal income tax liability for each of those years. The proposed changes result in a total tax deficiency, penalties and interest of approximately $23.9 million as of December 31, 2005. On November 4, 2005, we filed a written protest to one of the proposed changes. We believe we are adequately reserved for any tax deficiency, penalties and interest resulting from the proposed changes and as a result, the proposed changes did not adversely affect our results from operations.

We are also under audit review by various state agencies for tax years 2002 through 2004. We have also filed an appeal to the Ohio Board of Tax Appeals for tax years 1998 through 2001. Depending upon the outcome of these audits and the appeal, we may be required to increase our tax provision if actual amounts ultimately determined exceed recorded reserves. We believe we have adequate reserves in each tax jurisdiction but cannot predict the outcome of these audits.

On February 13, 2006, we received correspondence from the Ohio Department of Taxation (ODT) notifying us that ODT has completed their examination and review of our Ohio Corporation Franchise Tax Returns for tax years 2002 through 2004 and that the final proposed audit adjustments result in a balance due of $90.8 million before interest and penalties. We have reviewed the proposed audit adjustments and plan to vigorously contest the ODT findings and forthcoming notice of assessment through all administrative and judicial means available. We believe we have recorded adequate tax reserves related to the proposed adjustments; however, we cannot predict the outcome which could be material to our results of operations and cash flows.

On December 12, 2003, the Office of Federal Contract Compliance Programs (OFCCP) notified DP&L by letter alleging it had discriminated in the hiring of meter readers during 2000-2001 by utilizing credit checks to determine if applicants had paid their electric bills. On February 12, 2004, DP&L and the OFCCP entered into a Conciliation Agreement whereby DP&L agreed to distribute approximately $0.2 million in compensation to certain affected applicants. DP&L has completed these payments to the affected applicants and supplied to the OFCCP all follow-up reports required under the Conciliation Agreement.

In June 2002, a contractor’s employee received a verdict against DP&L for injuries he sustained while working at a DP&L power station. The Adams County Court of Common Pleas awarded the contractor’s employee compensatory damages of approximately $0.8 million and prejudgment interest of approximately $0.6 million. On April 28, 2004, the 4th District Court of Appeals upheld this verdict except the award for prejudgment interest. On September 1, 2004, the Ohio Supreme Court refused to hear the case, so the matter was remanded to the Adams County Court of Common Pleas for a re-determination of the amount of prejudgment interest that should be awarded. The trial court heard this matter on October 15, 2004. On November 1, 2004, DP&L paid approximately $976,000 to the contractor’s employee to satisfy the judgment and post-judgment interest. On December 6, 2004, the Adams County Court of Common Pleas ruled that the prejudgment interest should be reduced to approximately $30 thousand. Both parties appealed this decision. On January 25, 2006, the Fourth District Court of Appeals ruled in DP&L’s favor, finding it owed no prejudgment interest to the Plaintiff.

Additional information relating to legal proceedings involving DPL is contained in Item 1 – ENVIRONMENTAL CONSIDERATIONS, and Item 8 – Note 14 of Notes to Consolidated Financial Statements.

In November 2005, AMP-Ohio, a wholesale supplier of electricity to its thirteen member municipalities, requested arbitration of its power supply agreement with DP&L. AMP-Ohio alleges it has a right to receive certain capacity credits. DP&L disagrees with this position and has agreed to arbitrate the dispute. The arbitration is pending. We are unable at this time to determine whether this will have any material impact on our results of operations, cash flows or financial position.

Item 4 - Submission of Matters to a Vote of Security Holders

NONE

PART II

Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

As of December 31, 2005, there were 26,061 holders of record of our common equity, excluding individual participants in security position listings. The following table presents the high and low per

share sales prices for DPL common stock as reported by the New York Stock Exchange for each quarter of 2005 and 2004.

	2005		2004
	High	Low	High	Low
First Quarter	$ 26.77	$ 24.27	$ 20.77	$ 17.60
Second Quarter	$ 27.67	$ 24.08	$ 19.77	$ 17.21
Third Quarter	$ 28.12	$ 26.70	$ 20.64	$ 19.02
Fourth Quarter	$ 28.01	$ 24.55	$ 25.36	$ 20.30

As long as DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation 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. As of year-end, all earnings reinvested in the business of DP&L were available for DP&L common stock dividends. We expect all 2006 earnings reinvested in the business of DP&L to be available for DP&L common stock dividends, payable to DPL.

Issuer Purchases of Equity Securities
	(a)	(b)	(c)	(d)
Period	Total Number of Shares (or Units) Purchased	Average Price Paid per Share (or Unit)	Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (1)	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs

December 1-31, 2005	406,000	$26.10	406,000	$389.4 million

(1) Our Board announced the common share repurchase program in a press release dated July 28, 2005. In this announcement our Board authorized up to $400 million to be spent on the repurchase program without a specified expiration date. During December 2005, a total of 406,000 shares at a cost of $10.6 million were repurchased and settled in January 2006. These common shares are currently held as treasury shares. There were no other repurchases during 2005 and 2004.

On April 30, 2004, we and DP&L announced that we suspended our quarterly dividend payments. On December 1, 2004, we and DP&L resumed our regular quarterly dividends, including payments normally made in June and September.

On February 1, 2006, our Board of Directors authorized a 4% dividend increase on our common stock, raising the annual dividend on common shares from $0.96 per share to $1.00 per share.

On July 27, 2005, our Board authorized the repurchase up to $400 million of stock from time to time in the open market, through private transactions. During December 2005 a total of 406,000 shares at a cost of $10.6 million were repurchased and settled in January 2006. These shares are currently held as treasury shares. There were no other repurchases during 2005 and 2004.

Additional information concerning dividends paid on DPL common stock is set forth under Selected Quarterly Information in Item 8 – Financial Statements and Supplementary Data.

Information regarding our equity compensation plans as of December 31, 2005, is disclosed in Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, which incorporates such information by reference to our proxy statement for the 2006 Annual Meeting of Shareholders.

Item 6 - Selected Financial Data

		2005			2004		2003		2002		2001
	For the years ended December 31,
DPL Inc.:	Basic earnings (loss) per share of common stock:
	Continuing operations	$	1.03		1.01		0.96		1.48		1.87
	Discontinued operations	$	0.44		0.80		0.14		(0.72	)	(0.26	)
	Cumulative effect of accounting change (a)	$	(0.03	)	—		0.14		—		0.01
	Total basic earnings per common share	$	1.44		1.81		1.24		0.76		1.62
	Diluted earnings (loss) per share of common stock:
	Continuing operations	$	0.97		1.00		0.94		1.42		1.75
	Discontinued operations	$	0.41		0.78		0.14		(0.69	)	(0.24	)
	Cumulative effect of accounting change (a)	$	(0.03	)	—		0.14		—		0.01
	Total diluted earnings per common share	$	1.35		1.78		1.22		0.73		1.52

	Dividends paid per share	$	0.96		0.96		0.94		0.94		0.94
	Dividend payout ratio	66.7		%	53.0	%	75.8	%	123.7	%	58.0	%
	Earnings from continuing operations, net of tax	$	124.7		121.5		114.9		177.6		227.0
	Earnings (loss) from discontinued operations, net of taxes	$	52.9		95.8		16.6		(86.5	)	(31.2	)
	Cumulative effect of accounting change, net of taxes (a)	$	(3.2	)	—		17.0		—		1.0
	Net income	$	174.4		217.3		148.5		91.1		196.8

	Revenues (millions)	$	1,284.9		1,199.9		1,191.0		1,186.4		1,201.8
	Total construction additions (millions)	$	179.7		98.0		102.2		165.9		338.9
	Market value per share at December 31	$	26.01		25.11		20.88		15.34		24.08

DPL Inc.:	Electric sales (millions of kWh)
	Residential	5,520			5,140		5,071		5,302		4,909
	Commercial	3,901			3,777		3,699		3,710		3,618
	Industrial	4,332			4,393		4,330		4,472		4,568
	Other retail	1,437			1,407		1,409		1,405		1,369
	Total retail	15,190			14,717		14,509		14,889		14,464
	Wholesale	2,716			3,748		4,836		4,358		3,591
	Total	17,906			18,465		19,345		19,247		18,055

	At December 31,
DPL Inc.:	Book value per share	$	8.53		8.67		7.52		6.89		7.13
	Total assets (millions)	$	3,791.7		4,165.5		4,444.7		4,277.7		4,370.8
	Long-term debt (millions) (b)	$	1,677.1		2,117.3		1,954.7		2,142.3		2,150.8
	Trust preferred securities (b)	$	—		—		—		292.6		292.4

	At December 31,
DPL Inc.:	Senior unsecured debt ratings —
	Fitch Ratings	BBB-			BB		BBB		BBB		A-
	Moody’s Investors Service	Ba1			Ba3		Ba1		Baa2		Baa1
	Standard & Poor’s Corporation	BB			BB-		BB-		BBB-		BBB

DP&L:	Senior secured debt ratings —
	Fitch Ratings	A-			BBB		A		A		AA
	Moody’s Investors Service	Baa1			Baa3		Baa1		A2		A2
	Standard & Poor’s Corporation	BB			BB-		BBB-		BBB		BBB+

	Number of Shareholders
DPL Inc.:	Common	26,061			28,079		30,366		31,856		33,729
DP&L:	Preferred	329			357		402		426		476

(a) In 2003, we recorded a cumulative effect of an accounting change related to the adoption of SFAS 143 “Accounting for Asset Retirement Obligations”. In 2005, we recorded an additional obligation in response to FASB Interpretation Number (FIN) 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” See Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations.

(b) Excludes current maturities of long-term debt. Upon adoption of FASB Interpretation Number 46R “Consolidation of Variable

Interest Entities (Revised December 2003)—an interpretation of ARB No. 51” at December 31, 2003, DPL deconsolidated the DPL Capital Trust II.

Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

Certain statements contained in this discussion are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Matters discussed in this report that relate to events or developments that are expected to occur in the future, including management’s expectations, strategic objectives, business prospects, anticipated economic performance and financial condition and other similar matters constitute forward-looking statements. Forward-looking statements are based on management’s beliefs, assumptions and expectations of our future economic performance, taking into account the information currently available to management. These statements are not statements of historical fact. Such forward-looking statements are subject to risks and uncertainties and investors are cautioned that outcomes and results may vary materially from those projected due to various factors beyond our control, including but not limited to: abnormal or severe weather; unusual maintenance or repair requirements; changes in fuel costs and purchased power, coal, environmental emissions, gas and other commodity prices; increased competition; regulatory changes and decisions; changes in accounting rules; financial market conditions; and general economic conditions.

Forward-looking statements speak only as of the date of the document in which they are made. We disclaim any obligation or undertaking to provide any updates or revisions to any forward-looking statement to reflect any change in our expectations or any change in events, conditions or circumstances on which the forward-looking statement is based. (See FACTORS THAT MAY AFFECT FUTURE RESULTS.)

GENERAL OVERVIEW

The electric utility industry has historically operated in a regulated environment. However, in recent years, there have been a number of federal and state regulatory and legislative decisions aimed at promoting competition and providing customer choice. Market participants have therefore created new business models to exploit opportunities. The marketplace is now comprised of independent power producers, energy marketers and traders, energy merchants, transmission and distribution providers and retail energy suppliers. There have also been new market entrants and activity among the traditional participants, such as mergers, acquisitions, asset sales and spin-offs of lines of business. In addition, transmission systems are being operated by Regional Transmission Organizations (RTOs).

As part of Ohio’s electric deregulation law, all of the state’s investor-owned utilities were required to join an RTO. DP&L successfully integrated its 1,000 miles of high-voltage transmission into the PJM Interconnection, L.L.C. (PJM) RTO in October 2004. As an RTO, PJM’s role is to administer an electric marketplace and ensure the reliability of the high-voltage electric power system serving 51 million people in all or parts of Delaware, Indiana, Illinois, Kentucky, Maryland, Michigan, New Jersey, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM coordinates and directs the operation of the region’s transmission grid; administers a competitive wholesale electricity market, the world’s largest; and plans regional transmission expansion improvements to maintain grid reliability and relieve congestion.

On December 28, 2005, the PUCO approved DP&L’s Rate Stabilization Plan with certain modifications. The new Rate Stabilization Plan will phase into rates two new rate riders related to increasing fuel and environmental costs over a five-year period that runs from January 1, 2006 through December 31, 2010. The environmental portion of the increase, which goes into effect in 2007 and runs through 2010, will be avoidable for customers who switch generation providers. This Plan provides customers with price protection through capped generation prices through 2010 and provides some level of revenue stability for DP&L.

Fuel costs are impacted 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. Based on weather normalized sales, fuel costs are forecasted to be flat in 2006 compared to 2005 and are forecasted to increase approximately 5% in 2007 compared to 2006. This forecast assumes coal prices will increase approximately 10% in 2006 as compared to 2005 and remain flat in 2007 as compared to 2006.

On February 13, 2005, our subsidiaries, MVE and MVIC, entered into an agreement to sell their respective interests in forty-six private equity funds to AlpInvest/Lexington 2005, LLC, a joint venture of AlpInvest Partners and Lexington Partners, Inc. Sales proceeds and any related gains or losses were recognized as the sale of each fund closed. Among other closing conditions, each fund required the transaction to be approved by the respective general partner. During 2005, MVE and MVIC completed the sale of their interests in forty-three and a portion of one private equity funds resulting in a $46.6 million pre-tax gain ($53.1 million less $6.5 million professional fees) from discontinued operations and providing approximately $796 million in net proceeds, including approximately $52 million in net distributions from funds while held for sale. As part of this pre-tax gain, we realized $30 million that was previously recorded as an unrealized gain in other comprehensive income.

During this same period, MVE entered into alternative closing arrangements with AlpInvest/Lexington 2005, LLC for funds where legal title to said funds could not be transferred until a later time. Pursuant to these arrangements, MVE transferred the economic aspects of the remaining private equity funds, consisting of two funds and a portion of another fund, to AlpInvest/Lexington 2005, LLC without a change in ownership of the interests. The terms of the alternative arrangements do not meet the criteria for recording a sale. We are obligated to remit to AlpInvest/Lexington 2005, LLC any distributions MVE receives from these funds, and AlpInvest/Lexington 2005, LLC is obligated to provide funds to us to pay any contribution notice, capital call or other payment notice or bill for which MVE receives notice with respect to such funds. The alternative arrangements resulted in a deferred gain of $27.1 million until such terms of a sale can be completed (contingent upon receipt of general partner approvals of the transfer) and providing approximately $72 million in net proceeds on these funds. We recorded an impairment loss of $5.6 million to write down to estimated fair value the assets transferred pursuant to the alternative arrangements. Ownership of these funds will transfer after the general partner of each fund consents to the transfer. It is anticipated that ownership of these funds will transfer no later than the first quarter of 2007.

EARNINGS OVERVIEW

	Earnings Per Share (Basic)
	2005			2004		2003

Earnings from Continuing Operations	$	1.03		$	1.01	$	0.96
Earnings from Discontinued Operations	0.44			0.80		0.14
Cumulative Effect of Accounting Change	(0.03		)	—		0.14
Net Income	$	1.44		$	1.81	$	1.24

2005 Compared to 2004

In 2005, basic earnings per share were $0.37 lower than 2004. The decline was primarily due to a $0.36 per share decrease in Earnings from Discontinued Operations (represented by the private equity funds that we agreed to sell in February 2005). Basic earnings per share for Earnings from Continuing Operations were $0.02 higher in 2005 compared to 2004. Our operating income increased $2.6 million as a result of lower operating expenses, excluding fuel and purchased power, of $11.6 million that were offset by lower net margin of $9.0 million. Net margin is revenues less fuel and purchased power costs. The decrease in net margin of $9.0 million was the result of higher revenues of $85.0 million reflecting increased retail sales and ancillary revenues associated with participation in PJM that were more than offset by significantly higher fuel and purchased power costs of $94.0 million. The lower operating expenses, excluding fuel and purchased power, of $11.6 million was primarily due to lower operation and maintenance expense of $18.1 million that primarily resulted from lower

corporate costs. Also contributing to higher basic earnings per share in 2005 were higher investment income of $42.5 million (resulting from the sale of public securities and from interest on invested proceeds from the private equity funds sale) and lower interest expense of $22.5 million as a result of the refinancing of debt in 2004 and the early redemption and refinancing of debt in 2005, offset by a $61.2 million charge for the early redemption of debt.

Basic earnings per share for Income from Discontinued Operations decreased by $0.36 primarily due to lower investment income as a result of the sale of the private equity funds, offset by the related gains on the sale. In February of 2005,we agreed to sell our respective interests in forty-six private equity funds. Accordingly, investment income and related expenses for these funds have been recorded in 2005 as Discontinued Operations in the Consolidated Statements of Results of Operations, with prior period results for the private equity funds reclassified to Discontinued Operations.

For 2005, basic earnings per share includes a $0.03 after-tax charge related to the cumulative effect of a change in accounting for asset retirement obligations at certain power generating stations.

2004 Compared to 2003

In 2004, basic earnings per share were $0.57 higher than 2003. The increase was primarily due to a $0.66 per share increase in Earnings from Discontinued Operations (represented by the private equity funds that we agreed to sell in February 2005). Basic earnings per share for Earnings from Continuing Operations were $0.05 higher in 2004 compared to 2003. Our operating income declined $35.4 million as a result of relatively flat revenues and increased fuel, purchased power, and operation and maintenance expenses. Net electric margins declined $44.8 million and operation and maintenance expense increased $37.3 million, primarily due to higher corporate costs and increased electric production, transmission and distribution expenses, partially offset by lower amortization of regulatory assets of $48.3 million due to the completion of the three-year regulatory transition cost recovery period. The lower operating income of $35.4 million was offset by improved non-operating income and expense of $33.7 million which was due to the 2003 settlement of the shareholder litigation lawsuits and lower interest expense as a result of refinanced debt, partially offset by the 2003 release of an insurance claims reserve and lower investment income resulting from the 2003 gain on interest rate hedges that did not recur in 2004. A lower effective income tax rate related to the recognition in 2004 of state coal tax credits also contributed to higher net income in 2004 as compared to 2003.

Basic earnings per share for Earnings from Discontinued Operations increased by $0.66 due to improved investment performance in 2004 of the private equity funds. In February 2005, we agreed to sell our respective interests in forty-six private equity funds. Accordingly, 2004 and 2003 investment income and related expenses for these funds have been reclassified in 2005 as Discontinued Operations in the Consolidated Statements of Results of Operations.

Basic earnings per share for 2003 includes a credit of $0.14 related to the cumulative effect of a change in accounting for asset retirement obligations at certain power generating stations.

See Item 8 - Notes to Financial Statements and the Management’s Discussion and Analysis section “FACTORS THAT MAY AFFECT FUTURE RESULTS.”

RESULTS OF OPERATIONS

Income Statement Highlights

$ in millions	2005			2004			2003

Revenues:
Retail	1,066.6			1,036.8			1,021.7
Wholesale	133.3			135.1			159.3
RTO ancillary (a)	74.4			17.9			—
Other revenues, net of fuel costs	10.6			10.1			10.0
Total Revenues	$	1,284.9		$	1,199.9		$	1,191.0
Less: Fuel	336.9			263.1			234.6
Purchased power (b)	133.3			113.1			87.9
Net margins (c)	$	814.7		$	823.7		$	868.5

Net margins as a percentage of revenues	63.4		%	68.6		%	72.9		%

Operating income	$	339.1		$	336.5		$	371.9

(a) Revenues includes PJM revenues, discussed as ‘RTO ancillary revenues’ in the detail provided in Item 1 – Business.

(b) Purchased power includes charges from PJM of $48.5 million, $12.3 million and zero for 2005, 2004 and 2003 respectively.

(c) For purposes of discussing operating results, we present and discuss net 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.

Revenues

Revenues increased 7% to $1,284.9 million for 2005 compared to $1,199.9 million for 2004, reflecting an increase of $85.0 million. This increase was primarily the result of increased retail sales volume, higher average rates for wholesale revenues, and ancillary revenues associated with participation in PJM that was partially offset by lower wholesale sales volume. Retail revenues increased $29.8 million, primarily resulting from increased sales volume of $32.8 million and $2.8 million in higher average rates, partially offset by $5.8 million in lower miscellaneous retail revenues reflecting transmission services provided in 2004 that are now provided through PJM. Residential customers comprised the bulk of the increase in sales volume reflecting greater weather extremes experienced in 2005 compared to 2004 as cooling degree days were up 39% to 1,075 in 2005 compared to 771 in 2004 and heating degree days were up 4% to 5,702 in 2005 compared to 5,500 in 2004. Wholesale revenue decreased $1.8 million, primarily related to a $37.2 million decline in sales volume that was nearly offset by a $35.4 million increase related to higher average market rates. For 2005, ancillary revenues from RTOs were $74.4 million compared to $17.9 million for 2004, as we did not participate in PJM until October 2004. RTO ancillary revenues primarily consist of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves.

Revenues increased $8.9 million to $1,199.9 million in 2004 compared to $1,191.0 million in 2003. Retail revenues increased $15.1 million or 2% in 2004 resulting from higher retail sales volume. Wholesale revenues decreased $24.2 million or 15% in 2004 primarily relating to lower wholesale sales volume that was partially offset by higher average market rates. Ancillary revenues from PJM increased $17.9 million as we did not participate in PJM in 2003. Cooling degree-days increased 12% to 771 in 2004 compared to 687 in 2003.

Margins, Fuel and Purchased Power

For 2005, net margin of $814.7 million decreased by $9.0 million from $823.7 million for 2004. As a percentage of total revenues, net margin decreased by 5.2 percentage points to 63.6% from 68.4%. This decline is primarily the result of increased fuel and purchased power costs, partially offset by an

increase in revenues, principally from RTO ancillary revenues and higher average wholesale rates. Fuel costs, which include coal, gas, oil and emission allowance costs, increased by $73.8 million or 28% for 2005 compared to the same period in 2004 primarily resulting from higher average fuel prices of $64.1 million as well as increased generation of $9.7 million. Purchased power costs increased by $20.2 million for 2005 compared to 2004 primarily resulting from increased charges of $36.2 million associated with operating in PJM (we did not participate in PJM until October 2004) and $28.2 million related to higher average market prices, partially offset by $44.2 million related to lower purchased power volume.

The net margin of $823.7 million in 2004 decreased by $44.8 million from $868.5 million in 2003. This decline in net margin was primarily the result of a lower volume of wholesale sales and increased fuel and purchased power costs, partially offset by a slight increase in retail sales and ancillary PJM revenues. As a percentage of total revenues, net margin decreased by 4.3 percentage points to 68.6% in 2004 from 72.9% in 2003. This decrease in net margin rate was primarily attributable to higher fuel and purchased power costs per kWh. Fuel costs increased by $28.5 million or 12% in 2004 compared to 2003 primarily related to rising prices in the coal market. Purchased power costs including PJM costs increased by $25.2 million or 29% in 2004 compared to 2003, primarily resulting from higher average market prices.

Operation and Maintenance

$ in millions	2005 vs. 2004 change			2004 vs. 2003 change

Electric production, transmission and distribution costs	$	4.5		$	13.1
Pension and benefits	(0.7		)	7.8
Low Income Payment Program costs	(2.3		)	1.8
Sarbanes-Oxley compliance and external/internal audit fees	(3.5		)	6.4
Executive and management compensation	(5.8		)	(13.6		)
Legal and special investigations	(5.8		)	12.5
Directors’ & Officers’ liability insurance	(8.3		)	5.3
Other – net increase	3.8			4.0
Total	$	(18.1	)	$	37.3

Operation and maintenance expense decreased $18.1 million or 8% in 2005 compared to 2004 as a result of lower corporate costs that was partially offset by increased electric production, transmission and distribution expenses. Corporate costs declined from the prior year primarily resulting from a decrease of $8.3 million in Directors’ and Officers’ liability insurance premiums; approximately $5.8 million related to the decreased level of activity regarding various internal and governmental investigations as well as the securities litigation; $5.8 million in lower executive and management compensation costs; $3.5 million in reduced Sarbanes-Oxley 404 compliance costs and external/internal audit fees; $2.3 million in decreased Low Income Payment Program costs; and $0.7 million of lower benefits costs (a decrease of $2.8 million for a 2004 adjustment in disability reserves was nearly offset by an increase in pension costs of $2.1 million). These decreases were partially offset by a $4.5 million increase in electric production, transmission, and distribution costs, primarily related to generation operations costs for lime used for pollution control and electric production boiler maintenance costs as well as higher costs related to electric distribution operation and maintenance.

Operation and maintenance expense increased $37.3 million or 19% in 2004 compared to 2003 as a result of higher corporate costs and increased electric production, transmission, and distribution expenses. Corporate costs exceeded the prior year primarily resulting from an increase of approximately $12.5 million related to various internal and governmental investigations, litigation with

the Company’s former executives and securities litigation. In addition, pension and benefits costs increased by $7.8 million; Sarbanes-Oxley 404 compliance costs and external/internal audit fees increased $6.4 million; Directors’ and Officers’ liability insurance premiums increased $5.3 million and Low Income Payment Program costs increased $1.8 million. These increases to corporate costs were partially offset by a $13.6 million decrease in executive and management compensation. Electric production, transmission and distribution expenses increased $13.1 million, primarily related to planned maintenance during scheduled outages, ash disposal and other maintenance charges.

Depreciation and Amortization

Depreciation and amortization expense was $3.2 million higher in 2005 as compared to 2004 primarily as a result of completed projects in the distribution area (including new services, line transformers, poles, station equipment and, overhead and underground conductor) and in the production area (mainly due to the SCRs for Stuart, Killen and Zimmer) that were put into service in the second quarter of 2004.

Depreciation and amortization expense was $5.2 million or 4% higher in 2004 compared to 2003, as a result of completed construction projects and a full year of depreciation on environmental compliance equipment installations completed in 2003.

General Taxes

$ in millions	2005		2004		2005 vs. 2004 change			2003		2004 vs. 2003 change

kWh excise	$	52.9	$	50.5	$	2.4		$	49.6	$	0.9
Property	45.6		47.0		(1.4		)	47.3		(0.3		)
Other	8.8		7.8		1.0			6.6		1.2
Excise	—		—		—			5.4		(5.4		)
Total	$	107.3	$	105.3	$	2.0		$	108.9	$	(3.6	)

General taxes increased $2.0 million or 2% in 2005 compared to 2004. The increase is primarily from $2.4 million increased expense for the kWh excise tax resulting from higher sales volumes from electric retail customers. The increase in other taxes of $1.0 million includes higher payroll taxes, PUCO maintenance and the new State of Ohio Commercial Activities Tax. These increases were partially offset by lower property tax expense.

General taxes declined $3.6 million or 3% in 2004 compared to 2003 primarily as a result of a 2003 excise tax of $5.4 million related to the three year regulatory transition period that ended in 2003.

Amortization of Regulatory Assets

Amortization of regulatory assets increased $1.3 million to $2.0 million in 2005 as compared to the prior year primarily resulting from PJM start-up costs amortization of $1.1 million and PJM integration costs amortization of $0.2 million reflecting DP&L’s entrance into the PJM market on October 1, 2004.

Amortization of regulatory assets decreased $48.3 million in 2004 from 2003 primarily reflecting the completion in 2003 of the three-year regulatory transition cost recovery period granted by the Public Utilities Commission of Ohio.

Investment Income

Investment income increased by $42.5 million in 2005 compared to 2004 primarily resulting from a net gain on the disposal of public equity investments of $23.5 million and from $18.5 million in interest income, principally from new short-term investments.

Investment income decreased by $25.5 million in 2004 compared to 2003. This decrease is primarily the result of a 2003 realized gain on interest rate hedges of $21.2 million that did not recur in 2004, as well as gains on investments of $4.6 million and investment income of $4.2 million recognized in 2003 for equity securities not related to discontinued operations. These decreases were partially offset by a $3.4 million gain on investments denominated in Euros that occurred in 2004.

The portion of investment income related to the private equity funds sold in 2005 has been classified as discontinued operations. (See Note 11 of Notes to Consolidated Financial Statements.)

Interest Expense

Interest expense decreased $22.5 million or 14% compared to 2004 due to the debt reduction of $462.6 million and a full year impact of the $500 million debt retirement completed in 2004 (partially financed with a $175 million note).

Interest expense decreased $21.5 million or 12% in 2004 compared to 2003 primarily resulting from the refinancing of debt in 2004 and 2003 for which interest expense was lower by $25.1 million, despite $3.1 million of additional interest incurred in 2004 relating to the failure to file exchange offer registration statements and the failure to timely file the 2003 Form 10-K. This decrease in interest expense was partially offset by lower capitalized interest in 2004 compared to 2003 of $6.6 million.

Shareholder Litigation

In 2003, we recorded a $76.7 million charge for the settlement of shareholder lawsuits.

Charge for Early Redemption of Debt

In 2005, we recorded $61.2 million in charges resulting from premiums paid for the early redemption of debt, including write-offs of unamortized debt expense and debt discounts. (See Note 8 of Notes to Consolidated Financial Statements.)

Other Income

Other income was $10.2 million greater than 2004 primarily reflecting $3.5 million of additional gains realized in 2005 over 2004 resulting from sales of pollution control emission allowances; $1.6 million of lower fees resulting from the 2004 cancellation and replacement of DP&L’s revolving credit facility and our term loan termination and $1.5 million from the 2004 write-off of the remaining term loan debt expense resulting from our term loan termination.

Other income decreased $39.0 million in 2004 compared to 2003 primarily resulting from the $39.7 million release of the insurance claims reserve in 2003 relating to the termination of DP&L’s business interruption risk insurance policy. This expense increase was partially offset by a $8.4 million gain on the sale of pollution control emission allowances.

Income Tax Expense

Income tax expense from continuing operations for 2005 increased $13.4 million compared to prior year resulting from higher income, increased accrual for open tax years and lower state tax coal credits.

On June 30, 2005, Governor Taft signed House Bill 66 into law which significantly changed the tax structure in Ohio. The major provisions of the bill included phasing-out the Ohio Franchise Tax, phasing-out the Ohio Personal Property Tax for non-utility taxpayers and phasing-in a Commercial Activities Tax. The Ohio Franchise Tax phase-out required second quarter 2005 adjustments to income tax expense. Income taxes from continuing operations were reduced by $1.5 million while income taxes from discontinued operations were increased by $1.3 million as a result of the tax law change. Other applicable provisions of House Bill 66 have been reflected in the consolidated financial statements.

For 2004, income tax expense from continuing operations decreased $8.3 million compared to 2003 primarily reflecting the recognition of $11.7 million of available state tax credits related to the consumption of coal mined in Ohio and a 2003 adjustment for non-deductible compensation.

Discontinued Operations, Net of Tax

On February 13, 2005, our subsidiaries, MVE and MVIC, entered into an agreement to sell their respective interests in forty-six private equity funds to AlpInvest/Lexington 2005, LLC, a joint venture of AlpInvest Partners and Lexington Partners, Inc. Sales proceeds and any related gains or losses were recognized as the sale of each fund closed. Among other closing conditions, each fund required the transaction to be approved by the respective general partner. During 2005, MVE and MVIC completed the sale of their interests in forty-three and a portion of one private equity funds resulting in a $46.6 million pre-tax gain ($53.1 million less $6.5 million professional fees) from discontinued operations and providing approximately $796 million in net proceeds, including approximately $52 million in net distributions from funds while held for sale. As part of this pre-tax gain, we realized $30 million that was previously recorded as an unrealized gain in other comprehensive income.

During this same period, MVE entered into alternative closing arrangements with AlpInvest/Lexington 2005, LLC for funds where legal title to said funds could not be transferred until a later time. Pursuant to these arrangements, MVE transferred the economic aspects of the remaining private equity funds, consisting of two funds and a portion of another fund, to AlpInvest/Lexington 2005, LLC without a change in ownership of the interests. The terms of the alternative arrangements do not meet the criteria for recording a sale. We are obligated to remit to AlpInvest/Lexington 2005, LLC any distributions MVE receives from these funds, and AlpInvest/Lexington 2005, LLC is obligated to provide funds to us to pay any contribution notice, capital call or other payment notice or bill for which MVE receives notice with respect to such funds. The alternative arrangements resulted in a deferred gain of $27.1 million until such terms of a sale can be completed (contingent upon receipt of general partner approvals of the transfer) and provided approximately $72 million in net proceeds on these funds. We recorded an impairment loss of $5.6 million to write down to estimated fair value the assets transferred pursuant to the alternative arrangements. Ownership of these funds will transfer after the general partners of each of the separate funds consent to the transfer. It is anticipated that ownership of these funds will transfer no later than the first quarter of 2007.

	For the years ended December 31,
$ in millions	2005			2004			2003
Earnings from discontinued operations:
Investment income	$	41.3		$	178.5		$	43.8
Investment expenses	(9.5		)	(23.6		)	(18.5		)
Income from discontinued operations	31.8			154.9			25.3

Gain realized from sale	53.1			—			—
Broker fees and other expenses	(6.5		)	—			—
Loss recorded	(5.6		)	—			—
Net gain on sale	41.0			—			—

Earnings before income taxes	72.8			154.9			25.3
Income tax expense	(19.9		)	(59.1		)	(8.7		)
Earnings from discontinued operations, net	$	52.9		$	95.8		$	16.6

Cash Flow:
Net proceeds from sale of portfolio	$	744.2		$	—		$	—
Net proceeds from transfer	72.3			—			—
Net distributions from funds	51.9			203.9			83.1
Total cash flow from discontinued operations	$	868.4		$	203.9		$	83.1

Income from discontinued operations (pre-tax) for the year ended December 31, 2005 of $31.8 million is comprised of $41.3 million of investment income less $9.5 million of associated management fees

and other expenses. Income from discontinued operations (pre-tax) for the year ended December 31, 2004 of $154.9 million is comprised of $178.5 million of investment income less $23.6 million of associated management fees and other expenses.

For the year ended December 31, 2005, we recognized a $46.6 million pre-tax gain ($53.1 million less $6.5 million of professional fees), recorded a $5.6 million impairment loss, deferred gains of $27.1 million on transferred funds from discontinued operations, and provided approximately $868 million in net proceeds, including approximately $52 million in net distributions from funds held for sale. We will continue to incur minor amounts of fees in the near term.

(See Note 11 of Notes to Consolidated Financial Statements.)

Cumulative Effect of Accounting Change, Net of Tax

In 2005, the cumulative effect of an accounting change resulted in a charge of $3.2 million related to the adoption of the provisions of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations an interpretation of FASB Statement No. 143” (FIN 47). (See Note 1 of Notes to Consolidated Financial Statements.)

The cumulative effect of an accounting change in 2003 resulted in a credit of $17.0 million reflecting the adoption of the provisions of FASB Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). (See Note 1 of Notes to Consolidated Financial Statements.)

FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS

Our cash and cash equivalents totaled $595.8 million at December 31, 2005, compared to $202.1 million at December 31, 2004. In addition, we had $125.8 million of short-term investments available for resale at December 31, 2005. The increase in cash and short-term investments of $519.5 million was primarily attributed to $868.4 million of net proceeds received from the sale of the financial asset portfolio and $314.1 million from operating activities. These proceeds were used for the early retirement of a portion of long-term debt of $446.6 million, capital expenditures of $180.1 million, and dividends paid to common shareholders of $115.3 million.

During the third quarter of 2005, we began investing in Auction Rate Securities (ARS). ARS are variable rate state and municipal bonds that trade at par value. Interest rates on ARS are reset every seven, twenty-eight or thirty-five days through a modified Dutch auction. We have the option to hold at market, re-bid or sell each ARS on the interest reset date. Although ARS are issued and rated as long-term bonds, they are priced and traded as short-term securities available for resale because of the market liquidity provided through the interest rate reset mechanism. Each ARS purchased by us is tax-exempt, AAA rated and insured by a third-party insurance company.

We generated net cash from operating activities of $314.1 million, $132.7 million, and $350.2 million in 2005, 2004 and 2003, respectively. The net cash provided by operating activities for 2005 was primarily the result of operating profitability, partially offset by cash used for working capital, specifically for interest payments, accounts payable, and accounts receivable. The net cash provided by operating activities in 2004 was primarily the result of operating profitability, partially offset by cash used for the shareholder litigation settlement and cash used for working capital, specifically payments for taxes and inventories. The net cash provided by operating activities in 2003 was primarily the result of operating profitability and working capital, specifically the timing of tax payments. The tariff-based revenue from our energy business continues to be the principal source of cash from operating activities. Management believes that the diversified retail customer mix of residential, commercial, and industrial classes coupled with the rate relief approved by the PUCO for 2006 and beyond provides us with a reasonably predictable gross cash flow from utility operations.

Net cash flows provided by for investing activities were $689.6 million, $182.3 million, and $65.5 million in 2005, 2004, and 2003, respectively. Net cash flows provided by investing activities in 2003 were primarily due to capital expenditures and purchases of short-term investments and securities unrelated to discontinued operations, largely offset by the sale of short-term investments and securities unrelated to discontinued operations as well as the settlement of interest rate hedges. Net cash flows used for investing activities for 2005 were primarily due to capital expenditures and purchases of short-term investments and securities, partially offset by the sale of short-term investments and securities, all of which were unrelated to discontinued operations. Our capital expenditures increased in 2005 as compared to 2004 in response to more stringent environmental regulations. These increased capital expenditures are expected to continue for the next three years. Net cash flows used for investing activities for 2004 were primarily due to capital expenditures and purchases of short-term investments and securities unrelated to discontinued operations, largely offset by the sale of short-term investments and securities unrelated to discontinued operations as well as proceeds from the sale of property.

Net cash flows used for financing activities were $610.0 million, $450.5 million, and $118.9 million in 2005, 2004 and 2003, respectively. Net cash flows used for financing activities for 2005 were primarily the result of cash used to retire $462.6 million of long-term debt, pay premiums on the early redemption of debt of $54.7 million and pay dividends to common stockholders of $115.3 million. These uses of cash were partially offset by cash received relating to the exercise of stock options of $22.7 million. Net cash flows used for financing activities for 2004 were primarily the result of funds used for the retirement of $500 million of the 6.82% Series Senior Notes and dividends paid to common stockholders, partially offset by the issuance of $175 million unsecured 8% Series Senior Notes used to provide partial funding for the retirement of the $500 million 6.82% Series Senior Notes. Annual dividends declared increased to $0.96 per share in 2004 from $0.94 per share in 2003. Net cash flows used for financing activities in 2003 primarily related to dividends paid to common stockholders and the early retirement of long-term debt. These uses were largely offset by the net proceeds related to the issuance of lower-interest long-term debt.

We have obligations to make future payments for capital expenditures, debt agreements, lease agreements, capital calls and other long-term purchase obligations, and have certain contingent commitments such as guarantees. We believe our cash flows from operations, the remaining proceeds from the financial asset portfolio sale in 2005, the credit facilities (existing or future arrangements), the senior notes, and other short- and long-term debt financing, will be sufficient to satisfy our future working capital, capital expenditures and other financing requirements for the foreseeable future. Our ability to generate positive cash flows from operations is dependent on general economic conditions, competitive pressures, and other business and risk factors described in “Risk Factors” and “Factors That May Affect Future Results.” If we are unable to generate sufficient cash flows from operations, or otherwise comply with the terms of our credit facilities and the senior notes, we may be required to refinance all or a portion of our existing debt or seek additional financing alternatives. A discussion of each of our critical liquidity commitments is outlined below.

Capital Requirements

Construction additions were $180 million, $98 million and $102 million in 2005, 2004 and 2003, respectively, and are expected to approximate $365 million in 2006. Planned construction additions for 2006 relate to our environmental compliance program, power plant equipment, and our transmission and distribution system. During the last three years, capital expenditures of $144.0 million have been incurred to meet DPL’s state and federal standards for Nitrogen Oxide (NOx), Sulfur Dioxide (SO2) and mercury emissions from power plants.

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. Over the next three years, we are projecting to spend an estimated $750 million in capital projects, approximately 60% of which is to meet changing environmental standards. Our ability to complete our capital projects and the reliability of future service will be affected by our financial condition, the availability of internal and external funds at reasonable cost, and adequate and timely return on these capital investments. We expect to finance our construction additions in 2006 with a combination of cash and short-term investments on hand, tax-exempt debt and internally-generated funds.

Debt and Debt Covenants

At December 31, 2005, our scheduled maturities of long-term debt, including capital lease obligations, over the next five years are $0.9 million in 2006, $225.9 million in 2007, $100.7 million in 2008, $175.7 million in 2009 and $0.6 million in 2010. Substantially all property of DP&L is subject to the mortgage lien securing the first mortgage bonds. Debt maturities in 2006 are expected to be financed with a combination of internal funds and tax-exempt financing. Certain debt agreements contain reporting and financial covenants for which we are in compliance as of December 31, 2005 and expect to be in compliance during the near term.

On September 29, 2003, DP&L issued $470 million principal amount of First Mortgage Bonds, 5.125% Series due 2013. The net proceeds from the sale of the bonds, after expenses, were used on October 30, 2003, to (i) redeem $226 million principal amount of DP&L’s First Mortgage Bonds, 8.15% Series due 2026, at a redemption price of 104.075% of the principal amount plus accrued interest to the redemption date and (ii) redeem $220 million principal amount of DP&L’s First Mortgage Bonds, 7.875% Series due 2024, at a redemption price of 103.765% of the principal amount plus accrued interest to the redemption date. The 5.125% Series due 2013 were not registered under the Securities Act of 1933, but were offered and sold through a private placement in compliance with Rule 144A under the Securities Act of 1933. The bonds include step-up interest provisions requiring DP&L to pay additional interest if (i) DP&L’s registration statement was not declared effective by the SEC within 180 days from issuance of new bonds or (ii) the exchange offer was not completed within 210 days from the issuance of the new bonds. The registration statement was not declared effective and the exchange offer was not timely completed and, as a result, DP&L was required to pay additional interest of 0.50% until a registration statement was declared effective, at which point the additional interest was reduced by 0.25%. The remaining additional interest of 0.25% continued until the exchange offer was completed. The exchange offer registration statement for these securities was filed and declared effective on May 20, 2005 and the exchange was completed on June 23, 2005.

Issuance of additional amounts of first mortgage bonds by DP&L is limited by the provisions of its mortgage; however, management believes that DP&L continues to have sufficient capacity to issue first mortgage bonds to satisfy its requirements in connection with its current refinancing and construction programs. The amounts and timing of future financings will depend upon market and other conditions, rate increases, levels of sales and construction plans.

On March 25, 2004, we completed a $175 million private placement of unsecured 8% series Senior Notes due March 2009. The Senior Notes will not be redeemable prior to maturity except that we have the right to redeem the notes for a make-whole payment at the adjusted treasury rate plus 0.25%. The proceeds from these notes were used to provide partial funding for the retirement of $500 million of the 6.82% series Senior Notes redeemed on April 6, 2004. The proceeds from these notes, combined with $202 million of internal funds provided by the financial asset portfolio and $123 million from core operations, were used to fund the retirement of $500 million of the 6.82% series Senior Notes retired April 6, 2004.

(i) indebtedness incurred to refinance existing indebtedness, (ii) subordinated indebtedness and (iii) up to $150 million of additional indebtedness. In addition to the events of default specified in the indenture, an event of default under the notes includes a payment default or acceleration of indebtedness under any other indebtedness of ours or any of our subsidiaries which aggregates $25 million or more. The purchasers of the Senior Notes were granted registration rights in connection with the private placement under an Exchange and Registration Rights Agreement. Pursuant to this agreement, we were obligated to file an exchange offer registration statement by July 22, 2004, have the registration statement declared effective by September 20, 2004 and consummate the exchange offer by October 20, 2004. We failed to have a registration statement declared effective and to complete the exchange offer according to this timeline. As a result, we are accruing additional interest at a rate of 0.5% per annum per violation, up to an additional interest rate not to exceed in the aggregate 1.0% per annum. As each violation is cured, the additional interest rate will decrease by 0.5%. The exchange offer registration statement for these securities is expected to be filed with the SEC during the first quarter of 2006.

In May 2005, DP&L obtained a $100 million unsecured revolving credit agreement that extended and replaced its previous revolving credit agreement of $100 million. The new agreement, renewable annually, expires on May 30, 2010 and provides credit support for DP&L’s business requirements during this period. This may be increased up to $150 million. The facility contains one financial covenant: DP&L total debt to total capitalization ratio is not to exceed 0.65 to 1.00. This covenant is currently met. DP&L had no outstanding borrowings under this credit facility at December 31, 2005. Fees associated with this credit facility are approximately $0.2 million per year. Changes in credit ratings, however, may affect the applicable interest rate for DP&L’s revolving credit agreement.

On August 11, 2005, we repurchased approximately $207.6 million principal amount of our notes listed below pursuant to offers to purchase that commenced on July 14, 2005 and expired on August 10, 2005.

$ in millions Title of Security; CUSIP Number	Principal Amount Outstanding	Aggregate Principal Amount of Tendered Notes Accepted for Purchase
8.125% Capital Securities due 2031; 23330AAC4	$ 300.0	$ 105.0

6.875% Senior Notes due 2011; 233293AH2	$ 400.0	$ 102.6

The total consideration paid for these notes totaled $252.9 million, which includes accrued and unpaid interest.

In addition, on August 29, 2005, we redeemed $200 million of our 8.25% Senior Notes due 2007, leaving $225 million of our 8.25% Senior Notes outstanding.

We used a portion of the proceeds from the sale of the private equity funds in our financial asset portfolio to fund these repurchases and redemptions.

On May 15, 2005, we redeemed all of the outstanding 7.83% Senior Notes due 2007 in the amount of $39 million. A premium of 5.38% was paid on the 7.83% Senior Notes that were redeemed.

On August 17, 2005, DP&L completed the refinancing of $214.4 million of pollution control bonds. The specific issues refinanced consisted of:

• $41.3 million of Ohio Water Development Authority (OWDA) bonds;

• $137.8 million of Ohio Air Quality Development Authority (OAQDA) bonds; and

• $35.3 million of Boone County, Kentucky (Boone County) bonds.

On August 17, 2005, DP&L entered into a separate loan agreement with the OWDA, OAQDA and Boone County for new pollution control bonds with a weighted average interest rate of 4.78%. The proceeds of the bonds were used to repay the previously existing pollution control bonds with a weighted average interest rate of 6.26% on September 16, 2005. To secure the repayment of its obligations to the OWDA, OAQDA and Boone County, DP&L entered into a 43^rd Supplemental Indenture to its First and Refunding Mortgage for a like amount ($214.4 million) of First Mortgage Bonds with The Bank of New York serving as Trustee.

On February 17, 2006, DP&L renewed its $10 million Master Letter of Credit Agreement with a financial lending institution. This agreement supports performance assurance needs in the ordinary course of business. DP&L has certain contractual agreements for the sale and purchase of power, fuel and related energy services that contain credit rating related clauses allowing the counter parties to seek additional surety under certain conditions. As of December 31, 2005, DP&L had two outstanding letters of credit for a total of $2.2 million.

There are no inter-company debt collateralizations or debt guarantees between us and our subsidiaries. None of the debt obligations of DPL or DP&L are guaranteed or secured by affiliates and no cross-collateralization exists between any subsidiaries.

Credit Ratings

Currently, our senior unsecured and DP&L’s senior secured debt credit ratings are as follows:

	DPL Inc.	DP&L	Outlook	Effective

Fitch Ratings	BBB-	A-	Stable	July 2005
Moody’s Investors Service	Ba1	Baa1	Positive	July 2005
Standard & Poor’s Corp.	BB	BB	Positive	April 2005

Transfer of Assets to MVIC

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

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, 2005, these include:

	Payment Year
Contractual Obligations ($ in millions)	Total		Less Than 1 Year		2 – 3 Years		4 – 5 Years		More Than 5 Years
Long-term debt	$	1,674.1	$	—	$	324.9	$	175.0	$	1,174.2
Interest payments	1,068.8		109.9		180.9		144.8		633.2
Pension and postretirement payments	240.3		22.8		46.3		47.4		123.8
Capital leases	3.9		0.9		1.7		1.3		—
Operating leases	0.9		0.5		0.4		—		—
Coal contracts (a)	795.1		390.1		273.0		87.0		45.0
Other contractual obligations	506.3		358.5		147.8		—		—

Total contractual obligations	$	4,289.4	$	882.7	$	975.0	$	455.5	$	1,976.2

(a) DP&L-operated units

Long-term debt:

Long-term debt as of December 31, 2005, consists of DP&L's first mortgage bonds, tax-exempt pollution control bonds, DPL unsecured notes and includes current maturities and unamortized debt discounts. During 2005, we redeemed $446.6 million of long-term debt earlier than termed. (See Note 8 of Notes to Consolidated Financial Statements.)

Interest payments:

Interest payments associated with the Long-term debt described above.

Pension and postretirement payments:

As of December 31, 2005, we had estimated future benefit payments as outlined in Note 5 of Notes to Consolidated Financial Statements. These estimated future benefit payments are projected through 2015.

Capital leases:

As of December 31, 2005, we had two capital leases that expire in November 2007 and September 2010.

Operating leases:

As of December 31, 2005, we had several operating leases with various terms and expiration dates. Not included in this total is approximately $88,000 per year related to right of way agreements that are assumed to have no definite expiration dates.

Coal contracts:

DP&L has entered into various long-term coal contracts to supply portions of its coal requirements for its generating plants. Contract prices are subject to periodic adjustment, and have features that limit price escalation in any given year.

Other contractual obligations:

In January 2006, DP&L entered into a contract for limestone that is expected to generate an obligation of $6.0 million in 2006 through 2008, $10.5 million in 2009 through 2010 and $42.2 million thereafter. As of December 31, 2005, we had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.

DPL enters into various commercial commitments, which may affect the liquidity of its operations. At December 31, 2005, these include:

Credit facilities:

In May 2005, DP&L replaced its previous $100 million revolving credit agreement with a $100 million, 364-day unsecured credit facility that is renewable annually and expires on May 30, 2010. At December 31, 2005, there were no borrowings outstanding under this credit agreement. The new facility may be increased up to $150 million.

Guarantees:

DP&L owns a 4.9% equity ownership interest in an electric generation company. As of December 31, 2005, DP&L could be responsible for the repayment of 4.9%, or $14.9 million, of a $305 million debt obligation and also 4.9%, or $2.9 million, of a separate $60 million debt obligation. Both obligations mature in 2006.

Other:

We completed the sale of or entered into alternative closing arrangements for all private equity funds in our financial asset portfolio as of June 20, 2005. We have an obligation to fund any cash calls or other commitments in which the purchaser of the private equity funds defaults with respect to the funds for which we entered into an alternative closing arrangement. This obligation is estimated not to exceed $8.0 million.

MARKET RISK

As a result of its operating, investing and financing activities, we are subject to certain market risks, including changes in commodity prices for electricity, coal, environmental emissions and gas; and fluctuations in interest rates. Commodity pricing exposure includes the impacts of weather, market demand, increased competition and other economic conditions. For purposes of potential risk analysis, we use sensitivity analysis to quantify potential impacts of market rate changes on the results of operations. The sensitivity analysis represents hypothetical changes in market values that may or may not occur in the future.

Commodity Pricing Risk

Approximately 10 percent of our 2005 electric revenues were from sales of excess energy and capacity in the wholesale market. Energy and capacity in excess of the needs of existing retail customers are sold in the wholesale market when we can identify opportunities with positive margins. As of December 31, 2005, a hypothetical increase or decrease of 10% in annual wholesale revenues could result in approximately an $8 million increase or decrease to net income, assuming no increases in fuel and purchased power costs.

Fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percent of total operating costs in 2005 and 2004 were 50% and 44%, respectively. We have approximately 95% of the total expected coal volume needed for 2006 under contract. The percentage of coal under contract at our individual facilities is as low as 80%. Contracted coal volumes at certain facilities exceed 100% of the expected need. Due to the differences in contracted volumes at various facilities, it is expected we will be in the spot market for more than 5% of our 2006 coal volume at some facilities while we may make no spot purchases at other facilities. We may have excess coal volumes to meet 2007 needs at some facilities. The majority of our contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustment and some are priced based on market indices. Substantially all contracts have features that limit price escalations in any given year. Our 2006 emission allowance (SO2) consumption is expected to be similar to 2005. Our holdings of 2006 SO2 allowances are approximately equal to its expected needs. There may be small exchanges of allowances between 2006 and future years to balance our 2006 position. We do not expect to purchase allowances outright for 2006. The exact consumption of SO2 allowances will depend on market prices for power, availability of our generating units and the actual sulfur content of the coal burned. Fuel costs are impacted 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. Based on weather normalized sales, fuel costs are forecasted to be flat in 2006 compared to 2005 and are forecasted to increase approximately 5% in 2007 compared to 2006. This forecast assumes coal prices will increase approximately 10% in 2006 as compared to 2005 and remain flat in 2007 as compared to 2006.

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 production costs. As of December 31, 2005, a hypothetical increase or decrease of 10% in annual fuel and purchased power costs could result in approximately a $29 million increase or decrease to net income.

Interest Rate Risk

As a result of our normal borrowing and leasing activities, our 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. Our long-term debt represents publicly and privately held secured and unsecured notes and debentures with fixed interest rates. At December 31, 2005, we had no short-term borrowings.

The carrying value of our debt was $1,678 million at December 31, 2005, consisting of DP&L’s first mortgage bonds, DP&L’s tax-exempt pollution control bonds, our unsecured notes and DP&L’s capital leases. The fair value of this debt was $1,717.5 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The principal cash repayments and related weighted average interest rates by maturity date for long-term, fixed-rate debt at December 31, 2005, are as follows:

	Long-term Debt
Expected Maturity	Amount
Date	($ in millions)			Average Rate

2006	$		0.9	5.3%
2007	225.9			8.2%
2008	100.7			6.3%
2009	175.7			8.0%
2010	0.6			5.8%
Thereafter	1,174.2			6.0%
Total	$	1,678.0		6.6%

Fair Value	$	1,717.5

Debt maturities in 2006 are expected to be financed with internal funds.

Debt retirements occurring in 2005 are discussed under FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS, DEBT AND DEBT COVENANTS.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our consolidated financial statements are prepared in accordance with GAAP. In connection with the preparation of these financial statements, our management is required to make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and the related disclosure of contingent liabilities. These assumptions, estimates and judgments are based on our historical experience and assumptions that we believed 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. 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 costs; valuation allowances for receivables and deferred income taxes; the valuation of reserves related to current litigation; and assets and liabilities related to employee benefits.

Long-Lived Assets: In accordance with Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144), 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. Long-lived assets to be disposed of and/or held for sale are reported at the lower of carrying amount or fair value less cost to sell. We determine the fair value of these assets in the same manner as described for assets held and used.

Revenue Recognition: 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 collectibility is reasonably assured. We record electric revenues when delivered to customers. Customers are billed throughout the month as electric meters are read. We recognize revenues for retail 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. Our estimates of unbilled revenues use systems that consider various factors to calculate retail customer consumption at the end of each month. Given the use of these systems 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.

Additionally, DP&L is subject to regulatory orders addressing the justness and reasonableness of the PJM and Midwest Independent Transmission System Operator (MISO) rates and related revenue

distribution protocols. DP&L’s management is required to make assumptions, estimates and judgments relating to the possibility of refund of these revenues. These assumptions, estimates and judgments are based on management’s experience and are believed to be reasonable at the time. As a result of these assumptions, estimates and judgments, DP&L is deferring a portion of these revenues for which management believes is subject to refund. The deferred amount recorded was $20.5 million for 2005. The above amount collected under the Seams Elimination Charge Adjustment (SECA) rates are subject to refund, and the ultimate outcome of the proceeding establishing SECA rates is uncertain at this time. However, based on the amount of reserves established for this item, the results of this proceeding are not expected to have a material adverse effect on our financial condition, results of operations or cash flows.

Income Taxes: We apply the provisions of FASB Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (SFAS 109). SFAS 109 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 Taxes in the Consolidated Balance Sheets. Deferred Tax Assets are recognized for deductible temporary differences. Valuation reserves are provided 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, have been deferred for financial reporting purposes. These deferred investment tax credits are amortized over the useful lives of the property to which they are related. For rate-regulated operations, additional deferred income taxes and offsetting regulatory assets or liabilities are recorded to recognize that the income taxes will be recoverable/refundable through future revenues.

We file a consolidated U.S. federal income tax return in conjunction with our subsidiaries. The consolidated tax liability is allocated to each subsidiary as specified in our tax allocation agreement which provides a consistent, systematic and rational approach. (See Note 4 of Notes to Consolidated Financial Statements.)

Depreciation and Amortization: Depreciation expense is calculated using the straight-line method, which depreciates the cost of property over its estimated useful life. For generation, transmission and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 3.3% in 2005 and 3.4% in 2004 and 2003.

Regulatory Assets and Liabilities: Application of FASB Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71) depends on our ability to collect cost-based rates from customers. The recognition of regulatory assets requires a continued assessment of the recovery of the costs based on actions of the regulators. We capitalize incurred costs as deferred regulatory assets when there is a probable expectation that the costs incurred will be recovered in future revenues as a result of the regulatory process. Regulatory liabilities represent current recovery of expected future costs. When applicable we apply judgment in the use of these principles and these estimates are based on expected usage by a customer class over the designated recovery period. See Note 3 of Notes to Consolidated Financial Statements for further disclosure of regulatory amounts.

Asset Retirement Obligations: In accordance with FASB Statement of Financial Accounting Standards No.143, “Accounting for Asset Retirement Obligations” (SFAS 143) and FASB Interpretation No. 47 (FIN No. 47), “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143,” 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. SFAS 143 also requires that components of previously recorded depreciation related to the cost of removal of assets upon retirement, whether legal asset retirement obligations or not, must be removed from a company’s accumulated

depreciation reserve. We make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to asset retirement obligations. These assumptions and estimates are based on historical experience and assumptions that we believed to be reasonable at the time.

Unbilled Revenues: We record revenue for retail and other energy sales under the accrual method. For retail customers, revenues are recognized when the services are provided on the basis of periodic cycle meter readings and include an estimated accrual for the value of electricity provided from the meter reading date to the end of the reporting period. These estimates are based on the volume of energy delivered, historical usage and growth by customer class, and the effect of weather variations on usage patterns.

Financial Instruments: We apply the provisions of FASB Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS 115), for our investments in debt and equity financial instruments of publicly traded entities and classify the securities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholders’ equity. Declines in value that are other than temporary are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The valuation of public equity security investments is based upon market quotations. The cost basis for public equity security and fixed maturity investments is average cost and amortized cost, respectively.

Insurance and Claims Costs: In addition to insurance provided through third-party providers, a wholly-owned captive subsidiary (MVIC) of ours provides insurance coverage solely to us and to our subsidiaries. Insurance and Claims Costs on the Consolidated Balance Sheets includes insurance reserves of approximately $24 million and $25 million for 2005 and 2004, respectively, based on actuarial methods and loss experience data. Such reserves are actuarially determined, in the aggregate, based on a reasonable estimation of insured events occurring. 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.

During the three-year regulatory transition period ending December 31, 2003, business interruption policy payments from the captive subsidiary to DP&L and/or the release of the appropriate reserves occurred and were reflected in income. In June 2003, the ultimate value of the business interruption risk coverage was settled between MVIC and DP&L. The total settlement resulted in a $76 million reduction to insurance reserves of MVIC and a release from the business interruption policy reserve of $39.7 million, which is reported as Other Income in 2003.

In 2003, we submitted a claim for $10 million to MVIC to recover legal expenses related to the shareholder litigation. This claim was settled in December 2003.

Pension and Postretirement Benefits: We account for our pension and postretirement benefit obligations in accordance with the provisions of Statement of Financial Accounting Standards No. 87, “Employers’ Accounting for Pensions” and No. 106 “Employers’ Accounting for Postretirement Benefits Other than Pensions.” These standards require the use of assumptions, such as the discount rate and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans. We disclose our pension and postretirement benefit plans as prescribed by Statement of Financial Accounting Standards No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits, an amendment of FASB Statements No. 87, 88, and 106.”

In 2006, we maintained our long-term rate of return assumptions of 8.50% for pension and 6.75% for other postretirement benefits assets that reflect the effect of recent trends on our long-term view. We

also maintained our assumed discount rate of 5.75% for pension and postretirement benefits expense to reflect current interest rate conditions. Changes in other components used in the determination of pension and postretirement benefits costs will result in an overall increase of approximately $2 million in such costs in 2006 compared to 2005.

In future periods, differences in the actual return on pension plan assets and assumed return, or changes in the discount rate, will affect the timing of contributions to the pension plan, if any. We provide postretirement healthcare benefits to employees who retired prior to 1987. A one percentage point change in the assumed healthcare trend rate would affect postretirement benefit costs by approximately $0.1 million.

LEGAL AND OTHER MATTERS

A discussion of LEGAL AND OTHER MATTERS is described in Note 14 of Notes to Consolidated Financial Statements and in Item 3 - LEGAL PROCEEDINGS. Such discussions are incorporated by reference in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and made a part hereof.

Recently Issued Accounting Pronouncements

A discussion of recently issued accounting pronouncements is described in Note 1 of Notes to Consolidated Financial Statements and such discussion is incorporated by reference in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and made a part hereof.

Item 7A – Quantitative and Qualitative Disclosures about Market Risk

The information required by this item of Form 10-K is set forth in the MARKET RISK section under Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 8 – Financial Statements and Supplementary Data

DPL Inc.

Consolidated Statements of Results of Operations

	For the years ended December 31,
$ in millions except per share amounts	2005			2004 (a)			2003 (a)

Revenues	$	1,284.9		$	1,199.9		$	1,191.0

Operating expenses:
Fuel	336.9			263.1			234.6
Purchased power	133.3			113.1			87.9
Operation and maintenance	219.0			237.1			199.8
Depreciation and amortization	147.3			144.1			138.9
General taxes	107.3			105.3			108.9
Amortization of regulatory assets, net	2.0			0.7			49.0
Total operating expenses	945.8			863.4			819.1

Operating income	339.1			336.5			371.9

Investment income	49.0			6.5			32.0
Interest expense	(137.7		)	(160.2		)	(181.7		)
Shareholder litigation expense	—			—			(76.7		)
Charge for early redemption of debt	(61.2		)	—			—
Other income	15.4			5.2			44.2

Earnings from continuing operations before income taxes	204.6			188.0			189.7

Income tax expense	79.9			66.5			74.8

Earnings from continuing operations	124.7			121.5			114.9
Earnings from discontinued operations, net of tax	52.9			95.8			16.6
Cumulative effect of accounting change, net of tax	(3.2		)	—			17.0
Net Income	$	174.4		$	217.3		$	148.5

Average number of common shares outstanding (millions):
Basic	121.0			120.1			119.8
Diluted	129.1			122.1			121.7

Basic earnings per share of common stock:
Continuing operations	$	1.03		$	1.01		$	0.96
Discontinued operations	0.44			0.80			0.14
Cumulative effect of accounting change	(0.03		)	—			0.14
Net income per basic common share	$	1.44		$	1.81		$	1.24

Diluted earnings per share of common stock:
Continuing operations	$	0.97		$	1.00		$	0.94
Discontinued operations	0.41			0.78			0.14
Cumulative effect of accounting change	(0.03		)	—			0.14
Net income per diluted common share	$	1.35		$	1.78		$	1.22

Dividends paid per share of common stock	$	0.96		$	0.96		$	0.94

(a) Revised – See Note 11.

See Notes to Consolidated Financial Statements.

DPL Inc.

Consolidated Statements of Cash Flows

	For the years ended December 31,
$ in millions	2005			2004 (a)			2003 (a)

Cash Flows From Operating Activities:
Net income	$	174.4		$	217.3		$	148.5
Less: Earnings from discontinued operations	(52.9		)	(95.8		)	(16.6		)
Earnings from continuing operations and cumulative effect of accounting change	121.5			121.5			131.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	147.3			144.1			138.9
Amortization of regulatory assets, net	2.0			0.7			49.0
Charge for early redemption of debt	61.2			—			—
Cumulative effect of accounting change, net of tax	3.2			—			(17.0		)
Shareholder litigation	—			(70.0		)	66.6
Deferred income taxes	(7.1		)	22.2			(4.8		)
Captive insurance provision	(0.6		)	(1.1		)	(46.8		)
Income from interest rate hedges	—			—			(21.2		)
Gain on sale of other investments	(28.8		)	(3.3		)	(3.9		)
Gain on sale of property	—			(1.8		)	—
Changes in certain assets and liabilities:
Accounts receivable	(12.5		)	7.1			(3.7		)
Accounts payable	(11.7		)	(12.9		)	(8.1		)
Accrued taxes payable	15.0			(62.8		)	70.4
Accrued interest payable	(13.2		)	(8.0		)	(9.1		)
Prepayments	2.2			0.4			(7.4		)
Inventories	(8.0		)	(20.0		)	4.0
Deferred compensation assets	2.9			12.6			49.0
Deferred compensation obligations	6.7			5.2			(47.0		)
Other	34.0			(1.2		)	9.4
Net cash provided by operating activities	314.1			132.7			350.2

Cash Flows From Investing Activities:
Capital expenditures	(180.1		)	(87.7		)	(120.9		)
Purchases of short-term investments and securities	(641.2		)	(26.1		)	(75.8		)
Sales of short-term investments and securities	642.5			89.9			127.7
Settlement of interest rate hedges	—			—			51.4
Proceeds from the sale of property	—			2.3			—
Cash flow from discontinued operations	868.4			203.9			83.1
Net cash provided by investing activities	689.6			182.3			65.5

Cash Flows From Financing Activities:
Issuance of long-term debt, net of issue costs	211.2			174.7			465.1
Exercise of stock options	22.7			—			—
Retirement of long-term debt	(673.8		)	(510.4		)	(471.9		)
Premiums paid for early redemption of debt	(54.7		)	—			—
Retirement of preferred securities	(0.1		)	—			—
Dividends paid on common stock	(115.3		)	(114.8		)	(112.1		)
Net cash used for financing activities	(610.0		)	(450.5		)	(118.9		)

Cash and Cash Equivalents:
Net change	393.7			(135.5		)	296.8
Balance at beginning of year	202.1			337.6			40.8
Cash and cash equivalents at end of year	$	595.8		$	202.1		$	337.6

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	146.1		$	162.1		$	184.0
Income taxes paid, net	$	71.2		$	107.9		$	15.2

(a) Revised – See Note 11.

See Notes to Consolidated Financial Statement.

DPL Inc.

Consolidated Balance Sheets

	At December 31,
$ in millions	2005			2004

*Assets*
Property:
Property, plant and equipment	$	4,667.7		$	4,495.0
Less: Accumulated depreciation and amortization	(2,094.8		)	(1,964.9		)
Net property	2,572.9			2,530.1

Current assets:
Cash and cash equivalents	595.8			202.1
Short-term investments available for sale	125.8			—
Accounts receivable, less provision for uncollectible accounts of $1.0 and $1.1, respectively	194.9			175.7
Inventories, at average cost	80.2			72.1
Prepaid taxes	45.9			46.4
Other current assets	20.2			34.3
Total current assets	1,062.8			530.6

Other assets:
Financial assets:
Public securities	—			86.3
Private securities under the equity method	—			304.0
Private securities under the cost method	—			522.3
Total financial assets	—			912.6

Regulatory assets	83.8			74.0
Other deferred assets	72.2			118.2
Total other assets	156.0			1,104.8

Total Assets	$	3,791.7		$	4,165.5

See Notes to Consolidated Financial Statements.

DPL Inc.

Consolidated Balance Sheets

	At December 31,
$ in millions	2005			2004

*Capitalization and Liabilities*
Capitalization:
Common shareholders’ equity:
Common stock: par value $0.01 per share, 250,000,000 shares authorized and 163,724,211 shares issued at December 31, 2005 and 2004; 127,526,404 shares and 126,501,404 shares outstanding at December 31, 2005 and 2004, respectively	$	1.3		$	1.3
Other paid-in capital, net of treasury stock	25.1			15.8
Warrants	50.0			50.0
Common stock held by employee plans	(86.1		)	(85.7		)
Accumulated other comprehensive income	(14.2		)	65.5
Earnings reinvested in the business	1,062.0			997.1
Total common shareholders’ equity	1,038.1			1,044.0

Preferred stock	22.9			23.0

Long-term debt	1,677.1			2,117.3
Total capitalization	2,738.1			3,184.3

Current Liabilities:
Current portion – long-term debt	0.9			13.5
Accounts payable	130.2			113.4
Accrued taxes	178.5			137.2
Accrued interest	28.9			42.1
Other current liabilities	31.1			20.7
Total current liabilities	369.6			326.9

Deferred Credits:
Deferred taxes	327.0			384.8
Unamortized investment tax credit	46.4			49.3
Insurance and claims costs	24.3			24.9
Other deferred credits	286.3			195.3
Total deferred credits	684.0			654.3

Commitments and Contingencies (Note 14)

Total Capitalization and Liabilities	$	3,791.7		$	4,165.5

See Notes to Consolidated Financial Statements.

DPL Inc.

Consolidated Statements of Shareholders’ Equity

									Common
									Stock			Accumulated			Earnings
	Common Stock (a)			Other					Held by			Other			Reinvested
	Outstanding			Paid-in					Employee			Comprehensive			In the
$ in millions	Shares	Amount		Capital			Warrants		Plans			Income			Business			Total
Beginning balance	126,501,404	$	1.3	$	8.4		$	50.0	$	(89.6	)	$	(2.2	)	$	856.9		$	824.8

2003:
Net income															148.5
Net change in unrealized gains (losses) on financial instruments, net of reclassification adjustments												10.0
Net change in unrealized gains (losses) on foreign currency translation adjustments												37.3
Net change in deferred gains on cash flow hedges												29.4
Minimum pension liability												(0.2		)
Deferred income taxes related to unrealized gains (losses)												(16.6		)
Total comprehensive income																		208.4
Common stock dividends (b)															(140.8		)	(140.8		)
Employee / Director stock plans				0.2					5.2						1.1			6.5
Other				3.4														3.4

Ending balance	126,501,404	$	1.3	$	12.0		$	50.0	$	(84.4	)	$	57.7		$	865.7		$	902.3

2004:
Net income															217.3
Net change in unrealized gains (losses) on financial instruments, net of reclassification adjustments												9.3
Net change in unrealized gains (losses) on foreign currency translation adjustments												6.2
Net change in deferred gains on cash flow hedges												(1.5		)
Minimum pension liability												(0.4		)
Deferred income taxes related to unrealized gains (losses)												(5.8		)
Total comprehensive income																		225.1
Common stock dividends (b)															(86.2		)	(86.2		)
Employee / Director stock plans				4.1					(1.3		)				0.4			3.2
Other				(0.3		)									(0.1		)	(0.4		)

Ending balance	126,501,404	$	1.3	$	15.8		$	50.0	$	(85.7	)	$	65.5		$	997.1		$	1,044.0

2005:
Net income															174.4
Net change in unrealized gains (losses) on financial instruments, net of reclassification adjustments												(15.3		)
Net change in unrealized gains (losses) on foreign currency translation adjustments												(46.3		)
Net change in deferred gains on cash flow hedges												(3.4		)
Minimum pension liability												(63.0		)
Deferred income taxes related to unrealized gains (losses)												48.2
Total comprehensive income																		94.6
Common stock dividends (b)															(115.3		)	(115.3		)
Treasury shares purchased (c)				(10.6		)												(10.6		)
Treasury stock reissued	1,025,000			16.9											5.8			22.7
Employee / Director stock plans				3.0					(0.4		)							2.6
Other												0.1						0.1

Ending balance	127,526,404	$	1.3	$	25.1		$	50.0	$	(86.1	)	$	(14.2	)	$	1,062.0		$	1,038.1

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

(b) Common stock dividends were $0.94 per share in 2003 and $0.96 per share in 2004 and 2005.

(c) Number of shares outstanding at December 31, 2005 not affected by a transaction to purchase 406,000 shares began December 30^th for which the share repurchase was settled in early January 2006. See Note 6 of Notes to Consolidated Financial Statements.

See Notes to Consolidated Financial Statements.

DPL Inc.

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies and Overview

Description of Business

DPL Inc. (DPL, the Company, we, our, or ours unless the context indicates otherwise) is a diversified, regional energy company organized in 1985 under the laws of Ohio. We conduct our principal business in one business segment - Electric.

Our principal subsidiary is The Dayton Power and Light Company (DP&L). DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. DP&L also purchases retail peak load requirements from DPL Energy LLC (DPLE). Principal industries served include automotive, food processing, paper, plastic manufacturing, and defense. DP&L’s sales reflect the general economic conditions and seasonal weather patterns of the area. DP&L sells any excess energy and capacity into the wholesale market.

Our other significant subsidiaries (all of which are wholly-owned) include DPLE, which engages in the operation of peaking generating facilities; DPL Energy Resources, Inc. (DPLER), which sells retail electric energy under contract to major industrial and commercial customers in West Central Ohio; MVE, Inc. (MVE), which was primarily responsible for the management of our financial asset portfolio; DPL Finance Company, which provides financing to us and our subsidiaries; and Miami Valley Insurance Company (MVIC), a captive insurance company for us and our subsidiaries.

Basis of Consolidation

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP). The consolidated financial statements include the accounts of DPL and its majority-owned subsidiaries. Investments that are not majority owned are accounted for using the equity method when our investment allows us the ability to exert significant influence, as defined by GAAP. Undivided interests in jointly-owned generation facilities are consolidated on a pro rata basis. All material intercompany accounts and transactions are eliminated in consolidation.

Estimates, Judgments and Reclassifications

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 at the date of the financial statements and the revenue and expenses of the period reported. 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. 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 costs; valuation allowances for receivables and deferred income taxes; reserves recorded for income tax exposures; litigation; and assets and liabilities related to employee benefits. Actual results may differ from those estimates. Certain amounts from prior periods have been reclassified to conform to the current reporting presentation. In 2005, we have separately disclosed the earnings from discontinued operations, net of income taxes, which in prior periods were reported with elements of continued operations. In 2005, we have separately disclosed the investing portions of the cash flows attributable to its discontinued operations (there was no impact on the operating or investing portions of the cash flows), which in prior periods were reported on a combined basis as a single amount.

Revenues

We record revenue for services provided but not yet billed to more closely match revenues with expenses. Accounts receivable on the Consolidated Balance Sheets include unbilled revenue of $63.6 million and $60.5 million in 2005 and 2004, respectively. Also included in revenues are amounts charged to customers through a surcharge for recovery of uncollected amounts from certain eligible low-income households. These charges were $6.2 million for 2005, $8.3 million for 2004 and $6.3 million for 2003.

Allowance for Uncollectible Accounts

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

Property, Plant and 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. For regulated property, cost includes direct labor and material, allocable overhead costs and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. Capitalization of AFUDC ceases at either project completion or as of the date specified by regulators. AFUDC capitalized related to borrowed funds was zero in 2005 and 2004 and $0.1 million in 2003. AFUDC capitalized for equity funds was zero in 2005, $0.5 million in 2004 and $0.6 million in 2003.

For unregulated property, cost includes direct labor, material and overhead costs and interest capitalized during construction. Capitalized interest was $2.6 million in 2005, $1.8 million in 2004 and $8.3 million in 2003.

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.

Depreciation

Depreciation expense is calculated using the straight-line method, which depreciates the cost of property over its estimated useful life. For generation, transmission and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 3.3% in 2005 and 3.4% in both 2004 and 2003. Depreciation expense was $147.3 million in 2005, $144.1 million in 2004 and $138.9 million in 2003.

The following is a summary of property, plant and equipment with corresponding composite depreciation rates at December 31, 2005 and 2004:

$ in millions	2005		Composite Rate	2004		Composite Rate
Regulated:
Transmission	$	341.8	2.6%	$	337.8	2.6%
Distribution	968.9		3.4%	929.6		3.6%
General	63.1		9.5%	58.9		8.7%
Non-depreciable	54.0		0.0%	54.4		0.0%
Total regulated	$	1,427.8		$	1,380.7

Unregulated:
Production	$	3,008.3	3.2%	$	2,975.3	3.2%
Other	45.2		7.6%	43.4		7.2%
Non-depreciable	18.4		0.0%	18.2		0.0%
Total unregulated	$	3,071.9		$	3,036.9

Total property in service	$	4,499.7	3.3%	$	4,417.6	3.4%
Construction work in process	168.0		0.0%	77.4		0.0%

Total property, plant and equipment	$	4,667.7		$	4,495.0

Asset Retirement Obligations

We adopted the provisions of the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143) during 2003. SFAS 143 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 allocated to expense over the useful life of the asset. SFAS 143 also requires that components of previously recorded depreciation related to the cost of removal of assets upon retirement, whether legal asset retirement obligations or not, must be removed from a company’s accumulated depreciation reserve. Our legal obligations associated with the retirement of our long-lived assets under SFAS 143 consisted primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Application of SFAS 143 in 2003 resulted in an increase in net property, plant and equipment of $0.8 million, the recognition of an asset retirement obligation of $4.6 million and reduced our accumulated depreciation reserve by $32.1 million due to cost of removal related to the non-regulated generation assets. Beginning in January 2003, depreciation rates were reduced to reflect the discontinuation of the cost of removal accrual for applicable non-regulated generation assets. In addition, costs for the removal of retired assets are charged to operation and maintenance when incurred. Since the generation assets are not subject to Ohio regulation, we recorded the net effect of adopting this standard in our Consolidated Statement of Results of Operations. The total cumulative effect of the adoption of SFAS 143 increased net income and shareholders’ equity by $28.3 million before tax in 2003.

In March of 2005, the FASB issued FASB Interpretation No. 47 (FIN No. 47), “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” We implemented FIN No. 47 in the fourth quarter of 2005 effective January 1, 2005 for certain asset retirement obligations, primarily the removal of asbestos, at some of our generation stations. Application of FIN No. 47 resulted in an increase in our net property, plant and equipment of $1.8 million and an increase in our asset retirement obligation of $7.2 million. The difference of $5.3 million represents the before tax ($3.2 million after tax) cumulative effect of the adoption of FIN No. 47, as of January 1, 2005 on 2005 net income. The before tax impact on 2005 net income was $0.9 million ($0.5 million after tax) which consisted of $0.6 million of accretion expense and $0.3 million depreciation expense. The following table sets forth the effect of the accounting change on net income as previously reported for 2004 and 2003 as adjusted, if FIN No. 47 had been applied effective January 1, 2003. Application of FIN No. 47 would have had no impact on reported basic or dilluted earnings per share in 2004 and 2003.

($ in millions)	2004			2003
Reported net income	$	217.3		$	148.5
Earnings effect of adopting FIN No. 47	(0.5		)	(0.4		)
Adjusted net income	$	216.8		$	148.1

If FIN No. 47 had been applied as of January 1, 2003, our asset retirement obligation would have increased by $9.4 million and $10.3 million at January 1, 2004 and December 31, 2004, respectively. Our asset retirement obligation was $13.2 million at December 31, 2005, which consisted of $5.4 million related to the adoption of SFAS 143 in 2003 and $7.8 million related to the adoption of FIN No. 47 in 2005.

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 asset retirement obligations associated with these assets. We have recorded $81.7 million and $77.5 million in estimated costs of removal at December 31, 2005 and 2004, respectively, as regulatory liabilities for our transmission and distribution property. (See Note 3 of Notes to Consolidated Financial Statements.)

Regulatory Accounting

We apply the provisions of FASB Statement of Financial Accounting Standards No. 71 (SFAS 71), “Accounting for the Effects of Certain Types of Regulation.” In accordance with SFAS 71, regulatory assets and liabilities are recorded in the Consolidated Balance Sheets. Regulatory assets are the deferral of costs expected to be recovered in future customer rates and regulatory liabilities represent current recovery of expected future costs.

We evaluate our regulatory assets each period and believe recovery of these assets is probable. We have received or requested a return on certain regulatory assets for which we are currently recovering or seeking recovery through rates. (See Note 3 of Notes to Consolidated Financial Statements).

If we were required to terminate application of SFAS 71 for all of our regulated operations, we would have to record the amounts of all regulatory assets and liabilities in the Consolidated Statement of Results of Operations at that time. (See Note 3 of Notes to Consolidated Financial Statements.)

Accounts Receivable

Our accounts receivable includes utility customer receivables, amounts due from our partners for jointly-owned property, wholesale and subsidiary customer receivables and electric unbilled revenue. We also include miscellaneous accounts receivables such as refundable Franchise taxes. The amount is presented net of a provision for uncollectible accounts on the accompanying balance sheets.

Inventory

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

Emission Allowances

We account for our emission allowances as inventory, and record emission allowance inventory at historical cost. We calculate the weighted average cost by each vintage (year) for which emission allowances can be used, and charge to fuel costs the weighted average cost of emission allowances used each quarter. Emission allowances are added to inventory when the EPA issues us emission allowances at no cost or when we purchase emission allowances. Purchased emission allowances are recorded in inventory at the purchase price, including any related transaction fees. Emission allowances are deducted from inventory when used in the production of electricity or when we sell excess emission allowances. Emission allowances used during the production of electricity are charged to fuel costs at the weighted average cost for that vintage. The excess/(shortfall) of the sales price over the weighted average cost for any emission allowances sold, less related fees, is recorded as a gain/(loss) in other income. Emission allowances received as part of an exchange of emission allowances are recorded at the carrying cost of the emission allowances given up, with no gain or loss recorded.

Repairs and Maintenance

Costs associated with all planned work and maintenance activities, primarily power plant 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 either capitalized or expensed based on defined units of property as required by the Federal Energy Regulatory Commission (FERC).

Income Taxes

We apply the provisions of FASB Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (SFAS 109). SFAS 109 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 Taxes in the Consolidated Balance Sheet. Deferred tax assets are recognized for deductible temporary differences. Valuation reserves are provided unless it is more likely than not that the asset will be realized.

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. Cash and cash equivalents were $595.8 million at December 31, 2005 and $202.1 million at December 31, 2004.

Short-term Investments Available for Sale

As of December 31, 2005, we owned Auction Rate Securities (ARS) with a total par value of $125.8 million, which equals fair value. ARS are variable rate state and municipal bonds that trade at par value. Interest rates on ARS are reset every seven, twenty-eight or thirty-five days through a modified Dutch auction. We have the option to hold at market, re-bid or sell each ARS on the interest reset date. Although ARS are issued and rated as long-term bonds, they are priced and traded as short-term securities held for resale because of the market liquidity provided through the interest rate reset mechanism. Each ARS owned by us at year end was tax-exempt, AAA rated and insured by a third-party insurance company. Interest earned but not received is accrued at the end of each reporting period.

Captive Insurance Subsidiary

In addition to insurance provided through third-party providers, a wholly-owned captive subsidiary of ours provides insurance coverage solely to us and to our subsidiaries, Insurance and Claims Costs on the Consolidated Balance Sheets includes insurance reserves of approximately $24 million and $25 million for 2005 and 2004, respectively, based on actuarial methods and loss experience data. Such reserves are actuarially determined, in the aggregate, based on a reasonable estimation of insured events occurring. 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.

During the three-year regulatory transition period ending December 31, 2003, business interruption policy payments from MVIC to DP&L or the release of the appropriate reserves occurred and was reflected in income. In June 2003, the ultimate value of the business interruption risk coverage was settled between MVIC and DP&L. The total settlement resulted in a $76 million reduction to insurance reserves of MVIC and a release from the business interruption policy reserve of $39.7 million, which was reported as Other Income in 2003.

In 2003, we submitted a claim for $10 million to MVIC to recover legal expenses related to the shareholder litigation. This claim was settled in December 2003.

Financial Derivatives

We follow FASB Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activity” (SFAS 133), as amended. SFAS 133 requires that all derivatives be recognized as either assets or liabilities in the Consolidated Balance Sheets and be measured at fair value, and changes in the fair value be recorded in earnings, unless they are designated as a cash flow hedge of a forecasted transaction.

The FASB issued Statement of Financial Accounting Standards No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149). SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments, including those embedded in other contracts, and for hedging activities and is effective for contracts entered into or modified after June 30, 2003. This standard did not have a material effect on us.

We use forward contracts and options 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 required to meet full load requirements during times of peak demand or during planned and unplanned generation facility outages. 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. The FASB concluded that electric utilities could apply the normal purchases and sales exception for option-type contracts and forward contracts in electricity subject to specific criteria for the power buyers and sellers under capacity contracts. Accordingly, we apply the normal purchases and sales exception as defined in SFAS 133 and account for these contracts upon settlement.

In May 2003, DP&L entered into 60-day interest rate swaps designed to capture existing favorable interest rates in anticipation of future financings of $750 million first mortgage bonds. These hedges were settled in July 2003, at a fair value of $51.4 million, reflecting increasing U.S. Treasury interest rates, and as a result, DP&L received this amount. During 2003, the ultimate effectiveness of the hedges resulted in a gain of $30.2 million and was recorded in Accumulated Other Comprehensive Income on the Consolidated Balance Sheets. This amount is amortized into income as a reduction to interest expense over the ten- and fifteen-year lives of the hedges. The ineffective portion of the hedge of $21.2 million was recognized as Other Income on the Consolidated Statement of Results of Operations during 2003.

We held emission allowance options, which were in effect until December 31, 2004, that were classified as derivatives not subject to hedge accounting. The fair value of these contracts is reflected as Other Current Assets or Other Current Liabilities on the Consolidated Balance Sheets and changes in fair value are recorded as Other Income on the Consolidated Statements of Results of Operations. The effect was not material to results of operations during 2003 through 2004. We did not hold any emission allowance options in 2005.

Financial Instruments

We apply the provision of FASB Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS 115), for our investments in debt and equity financial instruments of publicly traded entities and classify the securities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholders’ equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The valuation of public equity security investments is based upon market quotations. The cost basis for public equity security and fixed maturity investments is average cost and amortized cost, respectively.

Prior to the sale of the financial asset portfolio, we accounted for our investments in private financial instruments under either the cost or equity method of accounting. The equity method of accounting was applied to those investments in limited partnership interests when our ownership was 5% or more of the private equity fund. Under the cost method, our private investments were carried at cost unless an other-than-temporary decline in value was recognized, and income was recognized as distributed by the private equity fund. Under the equity method, private investments were carried at our share of the capital of the private equity fund, and we recognized our share of the income reported by the private equity fund, which included unrealized gains and losses. Other-than-temporary declines in value were recognized currently in earnings.

Investment Income

Investment income included in the Consolidated Financial Statements is comprised of realized investment income from the following sources:

($ in millions)	2005		2004		2003

Public securities	$	23.9	$	1.1	$	9.2
Other	25.1		5.4		22.8
Total investment income	$	49.0	$	6.5	$	32.0

Investment income increased by $42.5 million in 2005 compared to 2004 primarily resulting from a net gain on the sale of public securities of $23.5 million and $18.5 million in interest income, principally on short-term investments and tax-exempt investments of public securities.

The portion of investment income related to the private equity funds sold in 2005 has been classified as discontinued operations. At December 31, 2005, we held no beneficial interests in limited partnerships. (See Note 11 of Notes to Consolidated Financial Statements).

Pension and Postretirement Benefits

We account for our pension and postretirement benefit obligations in accordance with the provisions of Statement of Financial Accounting Standards No. 87, “Employers’ Accounting for Pensions” and No. 106 “Employers’ Accounting for Postretirement Benefits Other than Pensions.” These standards require the use of assumptions, such as the discount rate and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans. We disclose our pension and postretirement benefit plans as prescribed by Statement of Financial Accounting Standards No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits, an amendment of FASB Statements No. 87, 88, and 106.”

Legal, Environmental and Regulatory Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our consolidated financial statements, as prescribed by GAAP, adequately reflect probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, and other matters, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our consolidated financial statements or will not have a material adverse effect on our consolidated results of operations, financial condition or cash flows. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2005, cannot currently be reasonably determined.

Recently Issued Accounting Standards

Stock-Based Compensation

In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard No.123 (revised 2004), “Share-Based Payment” (SFAS 123R). SFAS 123R replaces SFAS 123, “Accounting for Stock-Based Compensation”, and supersedes Accounting Principles Board Opinion No. 25 (Opinion 25), “Accounting for Stock Issued to Employees”. SFAS 123R requires a public entity to measure the cost of employee services received and paid for by equity instruments to be based on the fair-value of such equity on the grant date. This cost is recognized in results of operations over the period in which employees are required to provide service. Liabilities initially incurred will be based on the fair-value of equity instruments and then be re-measured 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 will be estimated using option-pricing models and excess tax benefits will be recognized as an addition to paid-in capital. Cash retained from the excess tax benefits will be presented in the statement of cash flows as financing cash inflows. The provisions of this Statement shall be effective for fiscal periods beginning after December 31, 2005. We are currently accounting for such share-based transactions granted after January 1, 2003, using SFAS 123, “Accounting for Stock-Based Compensation.”

We use the Black-Scholes option-pricing model to determine the fair value of each option as of the date of grant for expense incurred. In applying the Black-Scholes option-pricing model, the following assumptions were used:

Dividend yield - 3.8%
Risk-free interest rate - 3.6%
Expected option terms ranging from 0.5 to 4.5 years
Volatility factors ranging from 14% to 28%
Share price as of December 31, 2005 - $26.01
Option strike prices ranging from $14.95 to $29.63

SFAS 123R permits public companies to adopt its requirements using one of two methods; “modified prospective” method and “modified retrospective” method. Under the “modified prospective” method, compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS 123R for all new awards and for awards modified, repurchased, or canceled after the effective date, and (b) for all awards granted to employees prior to the effective date of SFAS 123R that remain unvested on the effective date. The “modified retrospective” method includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures for either (a) all prior periods presented or (b) prior interim periods of the year of adoption. We plan to adopt SFAS 123R using the modified prospective method. The adoption of SFAS 123R’s fair value method is expected to have an immaterial impact on our operating expenses for fiscal year 2006.

The Stock Incentive Units (SIUs) that meet the requirements of a liability will be marked to market each quarter. The SIUs that are fully vested will continue to be marked to market on a quarterly basis. Under SFAS123, these SIU’s were valued at the quarter end market price for our common shares. If SFAS 123R had been adopted at December 31, 2005, then a credit of $0.2 million would have been booked to comply with the new valuation method. The first quarter financials for 2006 will reflect the new valuation method and we are anticipating that a credit to compensation expense of approximately $0.2 million will be needed to comply with SFAS 123R.

Inventory Costs

In November 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4”. The amendments made by SFAS 151 clarify that abnormal amounts of idle facility expense, freight, handling costs, and wasted materials (spoilage) should be recognized as current-period

charges and require the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. The guidance is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. Earlier application is permitted for inventory costs incurred during fiscal years beginning after November 23, 2004. The adoption of SFAS 151 had no impact on our results of operations, cash flows and financial position.

Exchange of Nonmonetary Assets

In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 153, “Exchange of Nonmonetary Assets, an amendment of APB Opinion No. 29” (SFAS 153). The guidance in APB Opinion No. 29, “Accounting for Nonmonetary Transactions”, is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in that Opinion, however, included certain exceptions to that principle. SFAS 153 amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of SFAS 153 shall be effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The adoption of SFAS 153 had no impact on our results of operations, cash flows and financial position.

The American Jobs Creation Act of 2004

On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the Act). On December 21, 2004, the FASB issued two FASB Staff Positions (FSP) regarding the accounting implications of the Act related to (1) the deduction for qualified domestic production activities (FSP FAS 109-1) and (2) the one-time tax benefit for the repatriation of foreign earnings (FSP FAS 109-2). The guidance in the FSPs applies to financial statements for periods ending after the date the Act was enacted. The Act provides a deduction up to 9 percent (when fully phased-in) of the lesser of (a) qualified production activities income (as defined by the Act) or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). This tax deduction is limited to 50 percent of W-2 wages paid by the taxpayer. The Act also creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain dividends from controlled foreign corporations. We have incorporated all applicable provisions of the Act in our 2005 financial statements. The incorporation of these ‘Section 199’ provisions generated a tax benefit of $1.6 million during 2005.

Ohio House Bill 66

On June 30, 2005, Governor Taft signed House Bill 66 into law which significantly changed how we are taxed in Ohio. The major provisions of the bill included phasing-out the Ohio Franchise Tax, phasing-out the Ohio Personal Property Tax for non-utility taxpayers and phasing-in a Commercial Activities Tax. The Ohio Franchise Tax phase-out required second quarter 2005 adjustments to income tax expense. Income taxes from continuing operations were reduced by $1.5 million while income taxes from discontinued operations were increased by $1.3 million as a result of the tax law change. Other applicable provisions of House Bill 66 have been reflected in our consolidated financial statements.

Discontinued Operations

In November, 2004, the Emerging Issues Task Force (EITF) issued EITF 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations” (SFAS No. 144). This guidance should be applied to a component of an enterprise that is either disposed of or classified as held for sale in fiscal periods beginning after December 15, 2004. We have accounted for the sale of the private equity investments in the financial asset portfolio according to SFAS No. 144; and EITF 03-13 does not affect our results of operations, cash flows or financial position.

Accounting Changes and Error Corrections

In June 2005, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 154 (SFAS 154), “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”. This Statement replaces APB Opinion No. 20, “Accounting Changes,” and FASB Statement No. 3, “Reporting Accounting Changes in Interim Financial Statements,” and changes the requirements for the accounting for and reporting of a change in accounting principle. This Statement applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This Statement shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

Accounting for Conditional Asset Retirement Obligations

In March 2005, the Financial Accounting Standards Board issued FASB Interpretation No. 47 (FIN No. 47), “Accounting for Conditional Asset Retirement Obligations”. This Interpretation clarifies that the term ‘conditional asset retirement obligation’ as used in FASB Statement No. 143 (SFAS 143), “Accounting for Asset Retirement Obligations”, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred–generally upon acquisition, construction, or development and (or) through the normal operation of the asset. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. SFAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. This Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We adopted FIN No. 47 during the fourth quarter 2005, effective January 1, 2005. (See Asset Retirement Obligations in Note 1 to Notes to Consolidated Financial Statements).

2. Supplemental Financial Information

	At December 31,
$ in millions	2005			2004

Accounts receivable, net
Utility customers	$	71.1		$	62.7
Unbilled revenue	63.6			60.6
Partners in commonly-owned plants	37.7			29.5
Refundable franchise tax	14.3			7.7
Wholesale and subsidiary customers	6.6			10.0
Other	2.6			6.3
Provision for uncollectible accounts	(1.0		)	(1.1		)
Total accounts receivable, net	$	194.9		$	175.7

Inventories, at average cost:
Fuel and emission allowances	$	48.6		$	40.1
Plant materials and supplies	31.4			31.4
Other	0.2			0.6
Total inventories, at average cost	80.2			$	72.1

Other current assets:
Deposits and other advances	$	9.2		$	6.6
Current deferred income taxes	5.4			6.8
Prepayments	5.0			16.3
Other	0.6			4.6
Total other current assets	$	20.2		$	34.3

Other deferred assets:
Prepaid pension	$	—		$	38.2
Master Trust assets	32.0			34.8
Unamortized loss on reacquired debt	22.0			23.8
Unamortized debt expense	10.2			9.7
Investment in Capital Trust	6.8			10.0
Other	1.2			1.7
Total other deferred assets	$	72.2		$	118.2

Other current liabilities:
Customer security deposits and other advances	$	19.2		$	17.3
Payroll taxes payable	2.2			—
Other	9.7			3.4
Total other current liabilities	$	31.1		$	20.7

Other deferred credits:
Asset retirement obligations – regulated property	$	81.7		$	77.5
Trust obligations	74.5			68.2
Retirees health and life benefits	32.9			32.4
Deferred gain on sale of portfolio	27.1			—
Pension liability	23.5			—
SECA net revenue subject to refund	20.5			—
Asset retirement obligations-generation	13.2			5.1
Legal reserves	3.0			3.3
Environmental reserves	0.1			0.1
Other	9.8			8.7
Total other deferred credits	$	286.3		$	195.3

3. Regulatory Matters

We apply the provisions of SFAS 71 to our regulated operations. This accounting standard defines regulatory assets as the deferral of costs expected to be recovered in future customer rates and regulatory liabilities as current cost recovery of expected future expenditures.

Regulatory liabilities are reflected on the Consolidated Balance Sheets under the caption entitled “Deferred Credits and Other – Other”. Regulatory assets and liabilities on the Consolidated Balance Sheets include:

	At December 31,
$ in millions	2005		2004
Regulatory Assets:
Deferred recoverable income taxes	$	28.8	$	32.5
Electric Choice systems costs	19.8		19.8
Regional transmission organization costs	12.9		13.6
PJM administrative costs	5.6		—
PJM integration costs	1.9		—
Deferred storm costs	6.5		1.0
Power plant emission fees	3.8		3.6
Other costs	4.5		3.5
Total regulatory assets	$	83.8	$	74.0

Regulatory Liabilities:
Asset retirement obligations-regulated property	81.7		77.5
SECA net revenue subject to refund	20.5		—
Total regulatory liabilities	$	102.2	$	77.5

Regulatory Assets

Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow-through items as the result of amounts previously provided to customers. Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, deferred recoverable income taxes are amortized.

Electric Choice systems costs represent costs incurred to modify the customer billing system for unbundled rates and electric choice bills relative to other generation suppliers, supplier energy settlements, and information reports provided to the state administrator of the low-income electric program. In February 2005, the PUCO approved a stipulation allowing DP&L to recover certain costs incurred for modifications to its billing system from all customers in its service territory. The case was appealed to the Ohio Supreme Court, and is still pending. DP&L filed a subsequent case to implement the PUCO’s order to begin charging customers for billing costs. A hearing took place on January 23, 2006 in this case. A PUCO order is still pending.

Regional transmission organization costs represent costs incurred to join a Regional Transmission Organization that controls the receipts and delivery of bulk power within the service area and are being recovered over a 10-year period that commenced in October 2004.

PJM administration costs contain the administrative fees billed by PJM to DP&L as a member of the PJM Interconnection, LLC Regional Transmission Organization (RTO). Pursuant to a PUCO order issued on January 25, 2006, these deferred costs will be recovered over a 3-year period from retail ratepayers beginning February 2006.

PJM integration costs include infrastructure costs and other related expenses incurred by PJM to integrate DP&L into the RTO. Pursuant to a FERC order, the costs are being recovered over a 10-year period beginning May 2005 from wholesale customers within PJM.

Deferred storm costs (2004 and 2005) include costs incurred by DP&L to repair damage from the December 2004 and the January 2005 ice storms. DP&L filed to recover these costs from retail ratepayers over a two year period. A PUCO order is pending.

Power plant emission fees represent costs paid to the State of Ohio for environmental oversight that are or will be recovered over various periods under a PUCO rate rider from customers.

Other costs include consumer education advertising regarding electric deregulation and costs pertaining to the recent rate case and are or will be recovered over various periods.

Regulatory Liabilities

Asset retirement obligations reflect an estimate of amounts recovered in rates that are expected to be expended to remove existing regulated transmission and distribution property from service upon retirement.

SECA (Seams Elimination Charge Adjustment) net revenue subject to refund represents DP&L’s estimate of probable refunds for net revenue collected in 2005. SECA revenue and expenses represent FERC-ordered transitional payments for the use of transmission lines within PJM. These transitional payments are subject to refund, depending on the results of a FERC hearing in mid 2006. DP&L began receiving and paying these transitional payments in May of 2005. DP&L received $23 million net SECA revenue in 2005.

4. Income Taxes

	For the years ended December 31,
$ in millions	2005			2004			2003
Computation of Tax Expense
Federal income tax (a)	$	71.9		$	66.3		$	66.8

Increases (decreases) in tax resulting from-
State income taxes, net of federal effect (b)	1.2			1.2			(2.5		)
Depreciation	(1.3		)	(4.0		)	(2.3		)
Investment tax credit amortized	(2.9		)	(2.9		)	(2.9		)
Non-deductible compensation	0.2			—			13.4
Section 199 – domestic production deduction	(1.6		)	—			—
Accrual for open tax years (c)	11.2			5.3			4.6
Other, net	1.2			0.6			(2.3		)
Total tax expense (d)	$	79.9		$	66.5		$	74.8

Components of Tax Expense
Taxes currently payable (b)	$	85.0		$	44.3		$	79.7
Deferred taxes—
Regulatory assets	—			—			(17.3		)
Depreciation and amortization	(11.7		)	(3.3		)	(2.2		)
Insurance and claims costs	(0.2		)	(0.7		)	27.6
Shareholder litigation	—			23.2			(23.2		)
Other	9.7			5.9			13.1
Deferred investment tax credit, net	(2.9		)	(2.9		)	(2.9		)
Total tax expense (d)	$	79.9		$	66.5		$	74.8

Components of Deferred Tax Assets and Liabilities

	At December 31,
$ in millions	2005			2004
Net Non-Current Assets (Liabilities)
Depreciation/property basis	$	(402.2	)	$	(415.2	)
Income taxes recoverable	(10.1		)	(11.4		)
Regulatory assets	(9.4		)	(6.5		)
Investment tax credit	16.3			17.3
Investment loss	9.6			13.9
Compensation and employee benefits	38.7			34.9
Insurance	1.8			2.1
Other (e)	28.3			(19.9		)
Net non-current (liabilities)	$	(327.0	)	$	(384.8	)

Net Current Asset
Other	$	5.4		$	6.8
Net Current Asset	$	5.4		$	6.8

(a) The statutory tax rate of 35% was applied to pre-tax income from continuing operations before preferred dividends.

(b) We have recorded ($2.1) million, $11.7 million and $1.8 million in 2005, 2004 and 2003, respectively, for state tax credits available related to the consumption of coal mined in Ohio.

(c) We have recorded $11.2 million, $5.3 million and $4.6 million in 2005, 2004 and 2003, respectively, of tax provision for tax deduction or income positions taken in prior tax returns that we believe were properly treated on such tax returns but for which it is possible that these positions may be contested. The Internal Revenue Service has issued an examination report for tax years 1998 through 2003 that shows proposed changes to our federal income tax liability for each of those years. (See Note 15 of Notes to Consolidated Financial Statements.)

(d) Excludes $(2.1) million in 2005 and $11.3 million in 2003 of income taxes reported as cumulative effect of accounting change, net of income taxes. Also excludes $19.9 million in 2005, $59.1 million in 2004 and $8.7 million in 2003 of income taxes reported as discontinued operations.

(e) The Other non-current liabilities caption includes deferred tax assets related to state tax net operating loss carryforwards, net of related valuation allowances of $6.8 million in 2005 and $5.3 million in 2004. The majority of these net operating losses are Ohio franchise tax loss carryforwards that expire after the phase-out of the Ohio franchise tax is completed in 2008. Remaining Ohio franchise tax loss carryforwards after 2008 can be used to offset the Ohio Commercial Activity Tax liability and do not expire until after 2029.

5. Pension and Postretirement Benefits

DP&L sponsors a defined benefit plan for substantially all employees. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees, the defined benefit plan is based primarily on compensation and years of service. We fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA). In addition, DP&L has a Supplemental Executive Retirement Plan (SERP) for certain active and retired key executives. Benefits under this SERP have been frozen and no additional benefits can be earned.

Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits. DP&L has funded the union-eligible health benefit using a Voluntary Employee Beneficiary Association Trust.

We use a December 31 measurement date for the majority of our plans.

The following tables set forth our pension and postretirement benefit plans obligations, assets and amounts recorded on the Consolidated Balance Sheets as of December 31. The amounts presented in the following tables for pension include both the defined benefit pension plan and the Supplemental Executive Retirement Plan in the aggregate.

Change in Projected Benefit Obligation		Pension						Postretirement
($ in millions)		2005			2004			2005			2004
Projected benefit obligation at January 1		$	280.5		$	264.5		$	32.0		$	33.5
Service cost		3.9			3.5			—			—
Interest cost		15.7			16.0			1.8			1.9
Plan amendments		9.3			—			—			—
Actuarial (gain) loss		8.2			15.0			0.4			(0.3		)
Benefits paid		(18.5		)	(18.5		)	(3.1		)	(3.1		)
Projected benefit obligation at December 31		$	299.1		$	280.5		$	31.1		$	32.0

Change in Plan Assets ($ in millions)
Fair value of plan assets at January 1		$	265.9		$	258.9		$	8.9		$	9.7
Actual return on plan assets		12.2			25.1			0.1			0.2
Contributions to plan assets		0.4			0.4			2.0			2.1
Benefits paid		(18.5		)	(18.5		)	(3.1		)	(3.1		)
Fair value of plan assets at December 31		$	260.0		$	265.9		$	7.9		$	8.9

Reconciliation to the Consolidated Balance Sheets ($ in millions)
Funded status of the plan		$	(39.1	)	$	(14.6	)	$	(23.2	)	$	(23.1	)
Unrecognized transition (asset) liability	��	—			—			0.4			0.5
Unrecognized prior service cost		17.1			10.2			—			—
Unrecognized net (gain) loss		78.4			64.9			(9.6		)	(11.2		)
Net amount recognized		$	56.4		$	60.5		$	(32.4	)	$	(33.8	)

Total Amounts Recognized in the Consolidated Balance Sheets ($ in millions)
Other deferred assets		$	—		$	56.6		$	—		$	—
Accumulated other comprehensive income		66.9			3.9			—			—
Other deferred credits		(10.5		)	—			(32.4		)	(33.8		)
Net amount recognized		$	56.4		$	60.5		$	(32.4	)	$	(33.8	)

The accumulated benefit obligation for DP&L’s defined benefit plans was $287.6 million and $269.4 million at December 31, 2005, and 2004, respectively.

The net periodic benefit cost (income) of the pension and postretirement benefit plans at December 31 were:

Net Periodic Benefit (Income) Cost	Pension									Postretirement
($ in millions)	2005			2004			2003			2005			2004			2003
Service cost	$	3.9		$	3.5		$	3.3		$	—		$	—		$	—
Interest cost	15.7			16.0			16.3			1.8			1.9			2.1
Expected return on assets (a)	(21.5		)	(21.7		)	(25.1		)	(0.5		)	(0.6		)	(0.7		)
Amortization of unrecognized:
Actuarial (gain) loss	3.8			2.0			0.1			(0.8		)	(1.1		)	(1.3		)
Prior service cost	2.3			2.7			2.8			—			—			—
Transition obligation	—			—			—			0.2			0.2			0.2
Net pension benefit cost (income) before adjustments	4.2			2.5			(2.6		)	0.7			0.4			0.3
Special termination benefit cost (b)	0.2			—			—			—			—			—
Curtailment cost (c)	0.1			—			—			—			—			—
Net pension benefit cost (income) after adjustments	$	4.5		$	2.5		$	(2.6	)	$	0.7		$	0.4		$	0.3

(a) The market-related value of assets is equal to the fair value of assets at implementation with subsequent asset gains and losses recognized in the market-related value systematically over a three-year period.

(b) In 2005, a special termination benefit cost was recognized as a result of 16 employees who participated in a voluntary early retirement program and retired at various dates during 2005.

(c) In 2005, a curtailment cost was recognized as a result of a freeze in benefits for the remaining active employee participating in the Supplemental Executive Retirement Plan.

DP&L’s pension and postretirement plan assets were comprised of the following asset categories at December 31:

	Pension				Postretirement
Asset Category	2005		2004		2005		2004
Common stocks	9	%	9	%	—		—
Mutual funds	87	%	84	%	—		—
Cash and cash equivalents	1	%	3	%	—		4	%
Fixed income government securities	—		—		100	%	96	%
Alternative investments	3	%	4		—		—
Total	100	%	100	%	100	%	100	%

Plan assets are invested using a total return investment approach whereby a mix of equity securities, mutual funds, fixed income investments, alternative investments, and cash and cash equivalents 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. At December 31, 2005, $23.4 million of our common stock was held as plan assets.

DP&L’s expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investment, which uses 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 reasonability and appropriateness.

DP&L’s overall expected long-term rate of return on assets is approximately 8.50% for pension plan assets and approximately 6.75% for retiree welfare plan assets. This expected return is based exclusively on historical returns, without adjustments. There can be no assurance of DP&L’s ability to generate that rate of return in the future.

DP&L’s overall discount rate was evaluated in relation to the December 31, 2005 Hewitt Yield Curve. The Hewitt Yield Curve represents a portfolio of top-quartile AA-rated bonds used to settle pension obligations and supported a weighted average discount rate of 5.75% at December 31, 2005. Peer data and historical returns were also reviewed to verify the reasonability and appropriateness of DP&L’s discount rate used in the calculation of benefit obligations and expense.

The weighted average assumptions used to determine benefit obligations for the years ended December 31 were:

	Pension		Postretirement
Benefit Obligation Assumptions	2005	2004	2005	2004
Discount rate for obligations	5.75%	5.75%	5.75%	5.75%
Rate of compensation increases	4.00%	4.00%	—	—

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

Net Periodic Benefit (Income)	Pension			Postretirement
Cost Assumptions	2005	2004	2003	2005	2004	2003
Discount rate	5.75%	6.25%	6.75%	5.75%	6.25%	6.75%
Expected rate of return on plan assets	8.50%	8.50%	8.75%	6.75%	6.75%	6.75%
Rate of compensation increases	4.00%	4.00%	4.00%	—	—	—

The assumed health care cost trend rates at December 31 are as follows:

	Expense				Benefit Obligations
Health Care Cost Assumptions	2005		2004		2005		2004

Current health care cost trend rate	10.00	%	10.00	%	10.00	%	10.00	%
Ultimate health care cost trend rate	5.00	%	5.00	%	5.00	%	5.00	%
Ultimate health care cost trend rate – year	2010		2009		2011		2010

The assumed health care cost trend rates have a significant 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 postretirement benefit cost and the accumulated postretirement benefit obligation:

Effect of Change in Health
Care Cost Trend Rate ($ in millions)	Increase 1%	Decrease 1%

Service cost plus interest cost	$ 0.1	$ (0.1)
Benefit obligation	$ 1.7	$ (1.6)

The following benefit payments, which reflect future service, are expected to be paid as follows:

Estimated Future Benefit Payments
($ in millions)	Pension		Postretirement

2006	$	19.8	$	3.0
2007	$	20.0	$	3.1
2008	$	20.2	$	3.0
2009	$	20.5	$	3.0
2010	$	21.0	$	2.9
2011 – 2015	$	112.1	$	11.7

DP&L expects to contribute $0.4 million to its pension plan and $3.0 million to its other postretirement benefit plan in 2006.

6. Common Shareholders’ Equity

We have 250,000,000 authorized common shares, of which 127,526,404 are outstanding at December 31, 2005. We had 902,490 authorized but unissued shares reserved for its dividend reinvestment plan at December 31, 2005. The plan provides that either original issue shares or shares purchased on the open market may be used to satisfy plan requirements.

On July 27, 2005, our Board authorized the repurchase up to $400 million of stock from time to time in the open market, through private transactions. During December 2005 a total of 406,000 shares at a cost of $10.6 million were repurchased and settled as 203,000 shares on January 4, 2006 and 203,000 shares on January 5, 2006. These shares are currently held as treasury shares. There were no other repurchases during 2005 and 2004.

In September 2001, our Board of Directors renewed our Shareholder Rights Plan, attaching one right to each common share outstanding at the close of business on December 13, 2001. The rights separate from the common shares and become exercisable at the exercise price of $130 per right in the event of certain attempted business combinations. The renewed plan expires on December 31, 2011.

In February 2000, we entered into a series of recapitalization transactions including the issuance of $550 million of a combination of voting preferred and trust preferred securities and warrants to an affiliate of investment company Kohlberg Kravis Roberts & Co. (KKR). As part of this recapitalization transaction, 31.6 million warrants were issued. These warrants were sold for an aggregate purchase price of $50 million. The warrants are exercisable, in whole or in part, for common shares at any time during the twelve-year period commencing on March 13, 2000. Each warrant is exercisable for one common share, subject to anti-dilution adjustments. The exercise price of the warrants is $21.00 per common share, subject to anti-dilution adjustments.

In addition, in the event of a declaration, issuance or consummation of any dividend, spin-off or other distribution or similar transaction by us of the capital stock of any of our subsidiaries, additional warrants of such subsidiary will be issued to the warrant holder so that after the transaction, the

warrant holder will have the same interest in the fully diluted number of common shares of such subsidiary the warrant holder had in us immediately prior to such transaction.

Pursuant to the warrant agreement, we have reserved authorized common shares sufficient to provide for the exercise in full of all outstanding warrants.

During December 2004 and January 2005, Dayton Ventures, LLC requested that we transfer all of Dayton Ventures, LLC’s warrants to Lehman Brothers, Inc. (Lehman) in four transactions. Lehman has subsequently transferred a large number of these warrants to unaffiliated third parties. During one of these transactions in 2005, Dayton Ventures, LLC agreed to sell back to us at par all of the outstanding 6,600,000 voting preferred shares. As a result of the reduction of Dayton Ventures, Inc.’s warrant ownership below 12,640,000, Dayton Ventures, LLC was no longer eligible to receive an annual $1 million management, consulting and financial services fee and it no longer had the right to designate one person to serve as a director of the DPL and DP&L and no longer had the right to designate one person to serve as a non-voting observer of DPL and DP&L. Currently, Dayton Ventures, LLC does not have any ownership interest in us or DP&L.

We have a leveraged Employee Stock Ownership Plan (ESOP) to fund matching contributions to DP&L’s 401(k) retirement savings plan and certain other payments to full-time employees. Common shareholders’ equity is reduced for the cost of 3.8 million unallocated shares held by the trust and for 2.7 million shares related to other employee plans, of which a total of 6.5 million shares reduce the number of common shares used in the calculation of earnings per share.

Dividends received by the ESOP for unallocated shares were used to repay the principal and interest on an ESOP loan to us. As debt service payments were made on the loan, shares are released on a pro-rata basis. Dividends on the allocated shares are charged to retained earnings.

ESOP cumulative shares allocated to employees and outstanding for the calculation of earnings per share were 3.2 million in 2005, 3.0 million in 2004 and 2.8 million in 2003. Compensation expense associated with the ESOP, which is based on the fair value of the shares allocated, amounted to $3.1 million in 2005, $2.5 million in 2004 and $2.8 million in 2003.

7. Preferred Stock

DPL: Series B, no par value, 8,000,000 shares authorized; no shares outstanding as of December 31, 2005 and 6,600,000 shares outstanding as of December 31, 2004. As part of our 2000 recapitalization, 6.8 million shares of voting preferred securities, redeemable par value of $0.01 per share, were issued at an aggregate purchase price of $68,000. During 2001, we redeemed 200,000 shares. These preferred securities carried voting rights for up to 4.9% of our total voting rights and the nomination of one Board seat and one non-voting observer. See Note 15 of Notes to Consolidated Financial Statements. On January 12, 2005, we repurchased all of the outstanding voting preferred shares at par for an aggregate purchase price of $66,000.

DP&L: $25 par value, 4,000,000 shares authorized, no shares outstanding; and $100 par value, 4,000,000 shares authorized, 228,508 shares without mandatory redemption provisions outstanding.

Preferred Stock Rate		Current Redemption Price		Current Shares Outstanding at December 31, 2005	Par Value At December 31, 2005 ($ in millions) (a)		Par Value At December 31, 2004 ($ in millions)

DPL Series B	0.00%	$	0.01	—	$	—	$	0.1
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					$	22.9	$	23.0

(a) DPL purchased all of its outstanding Series B shares during 2005.

In February 2000, we entered into a series of recapitalization transactions including the issuance of $550 million of a combination of voting preferred and trust preferred securities and warrants to an affiliate of investment company KKR. As part of our 2000 recapitalization transaction, trust preferred securities sold to KKR had an aggregate face amount of $550 million, and were issued at an initial discounted aggregate price of $500 million, with a maturity of 30 years (subject to acceleration six months after the exercise of the warrants), and distributions at a rate of 8.5% of the aggregate face amount per year. We recognized the entire trust preferred securities original issue discount of $50 million upon issuance.

In August 2001, we issued $300 million of trust preferred securities to institutional investors at 8.125% and $400 million of senior unsecured notes at 6.875%. The August 2001 trust preferred securities have a term of 30 years and the senior unsecured notes have a term of 10 years. In the fourth quarter of 2003, we adopted FIN46R and deconsolidated the DPL Capital Trust II, which resulted in transferring the August 2001 trust preferred securities to the DPL Capital Trust II and establishing a note to Capital Trust II for $300 million at 8.125%.

The voting preferred shares (DPL Series B) were not redeemable, except at the option of the holder. We agreed to redeem such number so that at no time would the holder and its affiliates maintain an ownership interest of greater than 4.9% of the voting rights of DPL. Our Series B preferred shares may only be transferred or otherwise disposed of together with a corresponding number of warrants, unless the holder and its affiliates hold a greater number of warrants than our Series B preferred shares, in which case the holder may transfer any such excess warrants without transferring our Series B preferred shares. If the holder of a warrant wishes to exercise warrants that are not excess warrants, we will redeem simultaneously with the exercise of such warrants an equal number of our Series B preferred shares held by such holder. We repurchased 6,600,000 DPL Series B preferred shares on January 12, 2005 at par for an aggregate purchase price of $66,000. There are currently no Series B preferred shares outstanding.

The DP&L preferred stock may be redeemed at our option at the per-share prices indicated, plus cumulative accrued dividends.

As long as any DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation 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. As of year-end, all earnings reinvested in the business of DP&L were available for Common Stock dividends. DPL records dividends on preferred stock of DP&L as part of interest expense. We expect all 2006 earnings reinvested in the business of DP&L to be available for DP&L common stock dividends, payable to DPL.

8. Long-term Debt and Notes Payable

	At December 31,
$ in millions	2005			2004
First mortgage bonds maturing:
2013 - 5.125%	$	470.0		$	470.0
Pollution control series maturing through 2027 - 6.43% (a)	—			104.4
Pollution control series maturing through 2034 – 4.78% (a)	214.4			—

	684.4			574.4

Note to Capital Trust II 8.125% due 2031	195.0			300.0
Guarantee of Air Quality Development Obligations 6.10% Series due 2030	—			110.0
Senior Notes 6.875% Series due 2011	297.4			400.0
Senior Notes 6.25% Series due 2008	100.0			100.0
Senior Notes 8.25% Series due 2007	225.0			425.0
Senior Notes 8.00% Series due 2009	175.0			175.0
Notes maturing through 2007 - 7.83%	—			33.0
Obligations for capital leases	3.0			3.8
Unamortized debt discount and premium (net)	(2.7		)	(3.9		)
Total	$	1,677.1		$	2,117.3

(a) Weighted average interest rates for 2005 and 2004.

The amounts of maturities and mandatory redemptions for first mortgage bonds, notes and the capital leases are $0.9 million in 2006, $225.9 million in 2007, $100.7 million in 2008, $175.7 million in 2009 and $0.6 million in 2010. Substantially all property of DP&L is subject to the mortgage lien securing the first mortgage bonds.

On September 29, 2003, DP&L issued $470 million principal amount of First Mortgage Bonds, 5.125% Series due 2013. The net proceeds from the sale of the bonds, after expenses, were used on October 30, 2003, to (i) redeem $226 million principal amount of DP&L’s First Mortgage Bonds, 8.15% Series due 2026, at a redemption price of 104.075% of the principal amount plus accrued interest to the redemption date and (ii) redeem $220 million principal amount of DP&L’s First Mortgage Bonds, 7.875% Series due 2024, at a redemption price of 103.765% of the principal amount plus accrued interest to the redemption date. The 5.125% Series due 2013 were not registered under the Securities Act of 1933, but were offered and sold through a private placement in compliance with Rule 144A under the Securities Act of 1933. The bonds include step-up interest provisions requiring DP&L to pay additional interest if (i) DP&L’s registration statement was not declared effective by the SEC within 180 days from issuance of new bonds or (ii) the exchange offer was not completed within 210 days from the issuance of the new bonds. The registration statement was not declared effective and the exchange offer was not timely completed and, as a result, DP&L was required to pay additional interest of 0.50% until a registration statement was declared effective, at which point the additional interest was reduced by 0.25%. The remaining additional interest of 0.25% continued until the exchange offer was completed. The exchange offer registration for these securities was filed and declared effective on May 20, 2005 and the exchange was completed on June 23, 2005.

In May 2005, DP&L obtained a $100 million unsecured revolving credit agreement that extended and replaced its previous revolving credit agreement, of $100 million. The new agreement, renewable annually, expires on May 30, 2010 and provides credit support of DP&L’s business requirements during this period. This may be increased up to $150 million. The facility contains one financial covenant: DP&L total debt to total capitalization ratio is not to exceed 0.65 to 1.00. This covenant is currently met. DP&L had no outstanding borrowings under this credit facility at December 31, 2005. Fees associated with this credit facility are approximately $0.2 million per year. Changes in credit ratings, however, may affect the applicable interest rate for DP&L’s revolving credit agreement.

In February 2004, DP&L entered into a $20 million Master Letter of Credit Agreement with a financial lending institution. On February 24, 2005, DP&L entered into an amendment to extend the term of this Agreement for one year and reduce the maximum dollar volume of letters of credit to $10 million. On February 17, 2006, the company entered into a second amendment to extend the terms of this agreement another year. This agreement supports performance assurance needs in the ordinary course of business. DP&L has certain contractual agreements for the sale and purchase of power, fuel and related energy services that contain credit rating related clauses allowing the counterparties to seek additional surety under certain conditions. As of December 31, 2005, DP&L had two outstanding letters of credit for a total of $2.2 million.

In March 2004, we completed a $175 million private placement of unsecured 8% series Senior Notes due March 2009. The Senior Notes will not be redeemable prior to maturity except for a make-whole payment at the adjusted treasury rate plus 0.25%. The proceeds from these notes were used to provide partial funding for the retirement of $500 million of the 6.82% Senior Notes due April 2004. The 6.82% Senior Notes were retired on April 6, 2004. We are in the process of registering these senior notes with the SEC. We expect this registration to be completed in the second quarter of 2006.

The 8% series Senior Notes were issued pursuant to our indenture dated as of March 1, 2000, and pursuant to authority granted in our Board resolutions dated March 25, 2004. The notes impose a limitation on the incurrence of liens on the capital stock of any of our significant subsidiaries and require us and our subsidiaries to meet a consolidated coverage ratio of 2 to 1 prior to incurring additional indebtedness. The limitation on the incurrence of additional indebtedness does not apply to (i) indebtedness incurred to refinance existing indebtedness, (ii) subordinated indebtedness and (iii) up to $150 million of additional indebtedness. In addition to the events of default specified in the indenture, an event of default under the notes includes a payment default or acceleration of indebtedness under any other indebtedness of ours or any of our subsidiaries which aggregates $25 million or more. The purchasers were granted registration rights in connection with the private placement under an Exchange and Registration Rights Agreement. Pursuant to this agreement, we were obligated to file an exchange offer registration statement by July 22, 2004, have the registration statement declared effective by September 20, 2004 and consummate the exchange offer by October 20, 2004. We failed to have a registration statement declared effective and to complete the exchange offer according to this timeline. As a result, we are accruing additional interest at a rate of 0.5% per annum per violation, up to an additional interest rate not to exceed in the aggregate 1.0% per annum. As each violation is cured, the additional interest rate may decrease by 0.5%. The exchange offer registration for these securities is expected to be filed during the first quarter of 2006.

The terms of the private placement also required us to file our 2003 Form 10-K by July 30, 2004. Because we failed to meet this deadline, we were required to pay additional liquidated damages in the form of additional interest at a rate of 1.0% until November 5, 2004, the date the 2003 Form 10-K was filed with the SEC.

On August 11, 2005, we repurchased approximately $207.6 million principal amount of its notes listed below pursuant to offers to purchase that commenced on July 14, 2005 and expired on August 10, 2005.

$ in millions Title of Security; CUSIP Number	Principal Amount Outstanding	Aggregate Principal Amount of Tendered Notes Accepted for Purchase

8.125% Capital Securities due 2031; 23330AAC4	$ 300.0	$ 105.0
6.875% Senior Notes due 2011; 233293AH2	$ 400.0	$ 102.6

The total consideration paid for these notes totaled $252.9 million, which includes accrued and unpaid interest.

In addition, on August 29, 2005, we redeemed $200 million of the 8.25% Senior Notes due 2007, leaving $225 million of the 8.25% Senior Notes outstanding.

We used a portion of the proceeds from the sale of the private equity funds in our financial asset portfolio to fund these repurchases and redemptions.

On May 15, 2005 we redeemed all of the outstanding 7.83% Senior Notes due 2007 in the amount of $39 million. A premium of 5.38% was paid on the 7.83% Senior Notes that were redeemed.

On August 17, 2005, DP&L completed the refinancing of $214.4 million of pollution control bonds. The specific issues refinanced consisted of:

• $41.3 million of Ohio Water Development Authority (OWDA) bonds;

• $137.8 million of Ohio Air Quality Development Authority (OAQDA) bonds; and

• $35.3 million of Boone County, Kentucky (Boone County) bonds.

In 2005, DPL recorded $61.2 million of charges resulting from premiums paid for the early redemption of debt, including write-offs of unamortized debt expense.

9. Stock-Based Compensation

In 2000, our Board of Directors adopted and our shareholders approved The DPL Inc. Stock Option Plan. The plan provides that “no single Participant shall receive Options with respect to more than 2,500,000 shares.” The exercise price of options granted approximates the market price of the stock on the date of grant. Options granted in 2000 and 2001 represent three-year awards, which vested over five years from the grant date, and expire ten years from the grant date. Options granted in 2002 vested over three years and expire ten years from the grant date. Options granted in 2003 vest over five years and expire ten years from the grant date. In 2004, 200,000 options were granted that vest over nineteen months and expire approximately 6.5 years from the grant date; 20,000 options were

granted that vest in five months and expire ten years from the grant date and 30,000 options were granted that vest over three years and expire ten years from the grant date. In 2005, 350,000 options were granted that vest in June 2006 and expire three years from the grant date. At December 31, 2005, there were 1,488,500 options available for grant.

Summarized stock option activity was as follows:

	2005			2004			2003
Options:
Outstanding at beginning of year	6,165,500			6,895,500			7,143,500
Granted	350,000			250,000			100,000
Exercised	(1,025,000		)	—			—
Forfeited	(4,000		)	(980,000		)	(348,000		)
Outstanding at year-end *(a)*	5,486,500			6,165,500			6,895,500
Exercisable at year-end	4,100,000			—			—

Weighted average option prices per share:
Outstanding at beginning of year	$	21.39		$	21.19		$	21.47
Granted	$	26.82		$	21.86		$	15.88
Exercised	$	21.18		—			—
Forfeited	$	29.63		$	20.07		$	24.99
Outstanding at year-end	$	21.86		$	21.39		$	21.19
Exercisable at year-end	$	20.98		—			—

(a) We originally granted 300,000 options during 2002 to Mr. Peter H. Forster, formerly DPL’s Chairman, that caused the number of options to be held by Mr. Forster to exceed the maximum number allowed to be held by one participant under the option plan approved by the shareholders. Therefore, 200,000 options representing the excess over the allowable maximum have been revoked. The number of options forfeited has been increased by 980,000 in 2004 and 64,668 in 2003 to reflect additional forfeitures. The 980,000 options forfeited in 2004 and 3,620,000 options outstanding are in dispute due to our ongoing litigation with Mr. Forster, Mr. Koziar and Ms. Muhlenkamp.

The weighted-average fair value of options granted was $3.80, $4.23 and $2.68 per share in 2005, 2004 and 2003, respectively. The fair values of the options were estimated as of the dates of grant using a Black-Scholes option pricing model utilizing the following assumptions:

	2005		2004		2003

Volatility	25.6	%	28.5	%	24.0	%
Expected life (years)	2.2		6.4		8.0
Dividend yield rate	3.7	%	4.8	%	4.5	%
Risk-free interest rate	3.8	%	3.9	%	3.7	%

The following table reflects information about stock options outstanding at December 31, 2005:

		Options Outstanding			Options Exercisable
Range of Exercise Prices	Outstanding	Weighted- Average Contractual Life	Weighted- Average Exercise Price		Exercisable	Weighted- Average Exercise Price

$14.95-$21.00	4,700,000	4.5 years	$	20.44	4,060,000	$	20.94
$21.01-$29.63	786,500	3.7 years	$	28.01	40,000	$	24.48

We account for stock options granted on or after January 1, 2003, under the fair-value method set forth in FASB Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (SFAS 123). This standard requires the recognition of compensation expense for stock-based awards to reflect the fair value of the award on the date of grant. We follow Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (Opinion 25) and related Accounting Principles Board and FASB interpretations in accounting for stock-based

compensation granted before January 1, 2003. If we had used the fair-value method of accounting for stock-based compensation granted prior to 2003, net income and earnings per share would have been reported as follows:

	Year Ended December 31,
$ in millions	2005			2004			2003
Net income, as reported	$	174.4		$	217.3		$	148.5
Adjustments:
Total stock-based compensation expense determined under APB 25, net of related tax effects	(0.5		)	—			—
Total stock-based compensation expense determined under FAS 123, net of related tax effects	2.0			(3.0		)	(2.7		)
Pro-forma net income	$	175.9		$	214.3		$	145.8

Earnings per share:
Basic – as reported	$	1.44		$	1.81		$	1.24
Basic – pro-forma	$	1.45		$	1.78		$	1.22

Diluted – as reported	$	1.35		$	1.78		$	1.22
Diluted – pro-forma	$	1.36		$	1.75		$	1.20

10. Ownership of Facilities

DP&L and other Ohio utilities have undivided ownership interests in seven 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, as well as 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, 2005, DP&L had $119 million of construction in progress at such facilities. DP&L’s share of the operating cost of such facilities is included in the Consolidated Statement of Results of Operations, and its share of the investment in the facilities is included in the Consolidated Balance Sheets.

DP&L’s undivided ownership interest in such facilities at December 31, 2005, is as follows:

			DP&L
	DP&L Share		Investment
		Production	Gross Plant
	Ownership	Capacity	In Service
	(%)	(MW)	($ in millions)
Production Units:
Beckjord Unit 6	50.0	207	$	62
Conesville Unit 4	16.5	129	33
East Bend Station	31.0	186	195
Killen Station	67.0	412	421
Miami Fort Units 7&8	36.0	360	194
Stuart Station	35.0	832	365
Zimmer Station	28.1	365	1,041

Transmission (at varying percentages)			88

11. Discontinued Operations

	For the years ended December 31,
$ in millions	2005			2004			2003

Investment income	$	41.3		$	178.5		$	43.8
Investment expenses	(9.5		)	(23.6		)	(18.5		)
Income from discontinued operations	31.8			154.9			25.3

Gain realized from sale	53.1			—			—
Broker fees and other expenses	(6.5		)	—			—
Loss recorded	(5.6		)	—			—
Net gain on sale	41.0			—			—

Earnings before income taxes	72.8			154.9			25.3
Income tax expense	(19.9		)	(59.1		)	(8.7		)
Earnings from discontinued operations, net	$	52.9		$	95.8		$	16.6

On February 13, 2005, our subsidiaries, MVE and MVIC, entered into an agreement to sell their respective interests in forty-six private equity funds to AlpInvest/Lexington 2005, LLC, a joint venture of AlpInvest Partners and Lexington Partners, Inc. Sales proceeds and any related gains or losses were recognized as the sale of each fund closed. Among other closing conditions, each fund required the transaction to be approved by the respective general partner. During 2005, MVE and MVIC completed the sale of their interests in forty-three and a portion of one private equity funds resulting in a $46.6 million pre-tax gain ($53.1 million less $6.5 million professional fees) from discontinued operations and providing approximately $796 million in net proceeds, including approximately $52 million in net distributions from funds while held for sale. As part of this pre-tax gain, we realized $30 million that was previously recorded as an unrealized gain in other comprehensive income.

During this same period, MVE entered into alternative closing arrangements with AlpInvest/Lexington 2005, LLC for funds where legal title to said funds could not be transferred until a later time. Pursuant to these arrangements, MVE transferred the economic aspects of the remaining private equity funds, consisting of two funds and a portion of one fund, to AlpInvest/Lexington 2005, LLC without a change in ownership of the interests. The terms of the alternative arrangements do not meet the criteria for recording a sale. We are obligated to remit to AlpInvest/Lexington 2005, LLC any distributions MVE receives from these funds, and AlpInvest/Lexington 2005, LLC is obligated to provide funds to us to pay any contribution notice, capital call or other payment notice or bill for which MVE receives notice with respect to such funds. The alternative arrangements resulted in a deferred gain of $27.1 million until such terms of a sale can be completed (contingent upon receipt of general partner approvals of the transfer) and provided approximately $72.3 million in net proceeds on these funds. We recorded an impairment loss of $5.6 million to write down assets transferred pursuant to the alternative arrangements to estimated fair value. Ownership of these funds will transfer after the general partners of each of the separate funds consent to the transfer. It is anticipated that this will conclude no later than the first quarter of 2007.

Income from discontinued operations (pre-tax) for the year ended December 31, 2005 of $31.8 million is comprised of $41.3 million of investment income less $9.5 million of associated management fees and other expenses. Income from discontinued operations (pre-tax) for the year ended December 31, 2004 of $154.9 million is comprised of $178.5 million of investment income less $23.6 million of associated management fees and other expenses. Income from discontinued operations (pre-tax) for the year ended December 31, 2003 of $25.3 million is comprised of $43.8 million of investment income less $18.5 million of associated management fees and other expenses.

In 2005, we have separately disclosed the earnings from discontinued operations, net of income taxes, which in prior periods were reported with elements of continued operations. Also in 2005 we have separately disclosed the investing portions of the cash flows attributable to its discontinued operations (there was no impact on the operating or investing portions of the cash flows), which in prior periods were reported on a combined basis as a single amount.

Other assets and liabilities of the discontinued operation were as follows:

	2005		2004

Assets	$	16.0	$	23.8

Liabilities	$	42.4	$	8.3

Other assets in 2004 consist of prepaid management fees. Other liabilities consist primarily of legal and professional fees and a reserve for estimated obligations under certain consulting and employment agreements that are currently being challenged as described in Legal Proceedings.

12. Financial Instruments

The fair value of our financial instruments is based on current public market prices, discounted cash flows using current rates for similar issues with similar terms and remaining maturities or independent party valuations, which are believed to approximate market. The basis on which the cost of a security sold or the amount reclassified out of accumulated other comprehensive income was determined by specific identification. The table below presents the fair value, unrealized gains and losses, and cost of these instruments at December 31, 2005 and 2004.

	At December 31,
	2005											2004
			Gross Unrealized											Gross Unrealized
			Gains		Losses									Gains		Losses
$ in millions	Fair Value				less than 12 months			more than 12 months		Cost		Fair Value				less than 12 months			more than 12 months			Cost
Assets
Public Securities
Available-for-sale Securities	$	24.8	$	3.5	$	(3.1	)	$	—	$	24.4	$	107.0	$	18.4	$	—		$	(2.8	)	$	91.4
Other	—		—		—			—		—		0.8		0.8		—			—			—
Held-to-maturity Debt securities (a)	7.9		—		(0.3		)	—		8.2		14.7		—		(0.1		)	—			14.8

Private Securities
Cost method	—		—		—			—		—		522.3		27.8		—			—			494.5
Equity method	—		—		—			—		—		304.0		19.5		—			(0.9		)	285.4
Total assets	$	32.7	$	3.5	$	(3.4	)	$	—	$	32.6	$	948.8	$	66.5	$	(0.1	)	$	(3.7	)	$	886.1

Liabilities
Long-term debt (b)	$	1,717.5								$	1,678.0	$	2,266.7									$	2,130.8

Capitalization
Unallocated shares In ESOP	$	100.1								$	49.1	$	101.9									$	51.7

(a) Maturities range from 2006 to 2035.

(b) Includes current maturities.

In the normal course of business, we enter into various financial instruments, including derivative financial instruments. These instruments consist of forward contracts and options that are used to reduce our exposure to changes in energy and commodity prices. These financial instruments are designated at inception as highly effective cash-flow hedges and are measured for effectiveness both at inception and on an ongoing basis, with gains or losses deferred in Accumulated Other Comprehensive Income until the underlying hedged transaction is realized, canceled or otherwise terminated. The forward contracts and options generally mature within twelve months.

13. Earnings per Share

Basic earnings per share (EPS) are based on the weighted-average number of common shares outstanding during the year. Diluted earnings per share are based on the weighted-average number of common and common equivalent shares outstanding during the year, except in periods where the inclusion of such common equivalent shares is anti-dilutive. Excluded from outstanding shares for this weighted average computation are shares held by the Master Trust Plan for deferred compensation and by the ESOP.

For the years 2005, 2004, and 2003, respectively, approximately 0.5 million, 28.0 million, and 37.8 million warrants and stock options were excluded from the computation of diluted earnings per share because they were anti-dilutive. These warrants and stock options could be dilutive in the future.

The following illustrates the reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for income after discontinued operations and cumulative effect of accounting change:

$ in millions except per share amounts	2005					2004					2003
	(a) Income		Shares	Per Share		Income		Shares	Per Share		(a) Income		Shares	Per Share
Basic EPS	$	174.4	121.0	$	1.44	$	217.3	120.1	$	1.81	$	148.5	119.8	$	1.24

Effect of Dilutive Securities:
Stock Incentive Units			1.2					1.2					1.8
Warrants			6.1					0.6					—
Stock options			0.8					0.2					0.1

Diluted EPS	$	174.4	129.1	$	1.35	$	217.3	122.1	$	1.78	$	148.5	121.7	$	1.22

(a) Income after discontinued operations and cumulative effect of accounting change.

14. Commitments and Contingencies

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our consolidated financial statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. (See Note 1 of Notes to Consolidated Financial Statements.) 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 Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2005, cannot be reasonably determined.

Environmental Matters

We and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and law. In the normal course of business, DP&L has investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. DP&L has been identified, either by a government agency or by a private party seeking contribution to site clean-up costs, as a potentially responsible party (PRP) at two sites pursuant to state and federal laws. DP&L records liabilities for probable estimated loss in accordance with Statement of Financial Accounting Standards No. 5 (SFAS 5), “Accounting for Contingencies.” To the extent a probable loss can only be estimated by reference to a range of equally probable outcomes, and no amount within the range appears to be a better estimate than any other amount, DP&L accrues for the low end of the range. Because of uncertainties related to these matters accruals are based on the best information available at the time. DP&L evaluates the potential liability related to probable losses quarterly and may revise its estimates. Such revisions in the estimates of the potential liabilities could have a material effect on the Company’s results of operations and financial position.

Legal Matters

On March 15, 2005, Mr. Forster and Ms. Muhlenkamp filed a lawsuit in New York state court against the purchasers of the private equity investments in the financial asset portfolio and against outside counsel to us and DP&L concerning purported entitlements in connection with the purchase of those investments. We, DP&L and MVE are not defendants in that case; however, the three of us are parties to an indemnification agreement with respect to the purchaser defendants. We, DP&L and MVE filed a Motion for Preliminary Injunction in the Ohio case, requesting that the court issue a preliminary injunction against Mr. Forster and Ms. Muhlenkamp regarding the New York lawsuit. On August 18, 2005, the Ohio court issued a preliminary injunction against Mr. Forster and Ms. Muhlenkamp that precludes them from pursuing certain key issues raised by Mr. Forster and Ms. Muhlenkamp in their New York lawsuit that are identical to the issues raised in the pending Ohio lawsuit in the New York court or any other forum other than the Ohio litigation. In addition, the New York court has stayed the New York litigation pending the outcome of the Ohio litigation. Mr. Forster and Ms. Muhlenkamp have appealed the preliminary injunction and the appeal is pending at the Ohio Supreme Court.

We continue to evaluate all of the matters relevant to this litigation and are considering other claims against Defendants, Forster, Muhlenkamp and Koziar that include, but are not limited to, breach of fiduciary duty or other claims relating to personal and DPL investments, the calculation of benefits under the Supplemental Executive Retirement Program (SERP) and financial reporting with respect to such benefits, and with respect to Mr. Koziar, the fulfillment of duties owed to us as our legal counsel. Cumulatively through December 31, 2005, we have accrued for accounting purposes, obligations of approximately $52 million to reflect claims regarding deferred compensation, estimated MVE incentives and/or legal fees that Defendants assert are payable per contracts. We dispute Defendants’ entitlement to any of those sums and, as noted above, we are pursuing litigation against them contesting all such claims.

On or about June 24, 2004, the SEC commenced a formal investigation into the issues raised by the Memorandum. We are cooperating with the investigation.

On April 7, 2004, the Company received notice that the staff of the PUCO is conducting an investigation into the financial condition of DP&L as a result of the issues raised by the Memorandum. On May 27, 2004, the PUCO ordered DP&L to file a plan of utility financial integrity that outlines the actions the Company has taken or will take to insulate DP&L utility operations and customers from its unregulated activities. DP&L was required to file this plan by March 2, 2005. On February 4, 2005, DP&L filed its protection plan with the PUCO. On June 29, 2005, the PUCO closed its investigation, citing significant positive actions we had taken including changes in the Board of Directors as well as the executive management of DP&L, and that no apparent diminution of service quality had occurred because of the events that initiated the investigation.

On May 20, 2004, the staff of the SEC notified us that it was conducting an inquiry covering our exempt status under the Public Utility Holding Company Act of 1935 (the ‘35 Act). The staff of the SEC requested we provide certain documents and information on a voluntary basis. On October 8, 2004, we received a notice from the SEC that a question exists as to whether such exemption from the Public Utility Holding Company Act may be detrimental to the public interest or the interests of investors or consumers. On November 5, 2004, we filed a good faith application seeking an order of exemption from the SEC. In light of the repeal of the ‘35 Act, effective February 8, 2006, and based upon the information previously provided to the staff of the SEC, this inquiry is moot.

On February 13, 2006, we received correspondence from the Ohio Department of Taxation (ODT) notifying us that ODT has completed their examination and review of our Ohio Corporation Franchise Tax Returns for tax years 2002 through 2004 and that the final proposed audit adjustments result in a balance due of $90.8 million before interest and penalties. We have reviewed the proposed audit adjustments and plan to vigorously contest the ODT findings and forthcoming notice of assessment through all administrative and judicial means available. We believe we have recorded adequate tax reserves related to the proposed adjustments; however, we cannot predict the outcome, which could be material to our results of operations and cash flows.

On December 12, 2003, the Office of Federal Contract Compliance Programs (OFCCP) notified DP&L by letter, alleging it had discriminated in the hiring of meter readers during 2000-2001 by utilizing credit checks to determine if applicants had paid their electric bills. On February 12, 2004 DP&L and the OFCCP entered into a Conciliation Agreement whereby DP&L agreed to distribute approximately $0.2 million in compensation to certain affected applicants. DP&L has completed these payments to the affected applicants and supplied to the OFCCP all follow-up reports required under the Conciliation Agreement.

In June 2002, a contractor’s employee received a verdict against DP&L for injuries he sustained while working at a DP&L power station. The Adams County Court of Common Pleas awarded the contractor’s employee compensatory damages of approximately $0.8 million and prejudgment interest of approximately $0.6 million. On April 28, 2004, the 4th District Court of Appeals upheld this verdict except the award for prejudgment interest. On September 1, 2004, the Ohio Supreme Court refused to hear the case, so the matter was remanded to the Adams County Court of Common Pleas for a re-determination of the amount of prejudgment interest that should be awarded. The trial court heard this matter on October 15, 2004. On November 1, 2004, DP&L paid approximately $976 thousand to the contractor’s employee to satisfy the judgment and post-judgment interest. On December 6, 2004, the Adams County Court of Common Pleas ruled that prejudgment interest should be reduced to approximately $30 thousand. Both parties appealed this decision. On January 25, 2006, the Fourth District Court of Appeals ruled in DP&L’s favor, finding it owed no prejudgment interest to Plaintiff.

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, 2005, these include:

			Payment Year
Contractual Obligations ($ in millions)	Total		Less Than 1 Year		2 – 3 Years		4 – 5 Years		More Than 5 Years
Long-term debt	$	1,674.1	$	—	$	324.9	$	175.0	$	1,174.2
Interest payments	1,068.8		109.9		180.9		144.8		633.2
Pension and postretirement payments	240.3		22.8		46.3		47.4		123.8
Capital leases	3.9		0.9		1.7		1.3		—
Operating leases	.9		0.5		0.4		—		—
Coal contracts (a)	795.1		390.1		273.0		87.0		45.0
Other contractual obligations	506.3		358.5		147.8		—		—

Total contractual obligations	$	4,289.4	$	882.7	$	975.0	$	455.5	$	1,976.2

(a) DP&L-operated units

Long-term debt:

Long-term debt as of December 31, 2005, consists of DP&L first mortgage bonds, tax-exempt pollution control bonds, DPL unsecured notes and includes current maturities and unamortized debt

discounts. As of December 31, 2005, we have redeemed $446.6 million of long-term debt earlier than termed. (See Note 8 of Notes to Consolidated Financial Statements.)

Interest payments:

Interest payments associated with the Long-term debt described above.

Pension and Postretirement payments:

Capital leases:

As of December 31, 2005, we had two capital leases that expire in November 2007 and September 2010.

Operating leases:

Coal contracts:

Other contractual obligations:

In January 2006, DP&L entered a contract for limestone that is expected to generate an obligation of $6.0 million in 2006 through 2008, $10.5 million in 2009 through 2010 and $42.2 million thereafter. As of December 31, 2005, we had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.

We enter into various commercial commitments, which may affect the liquidity of our operations. At December 31, 2005, these include:

Credit facilities:

Guarantees:

Other:

15. Certain Relationships and Related Transactions

On March 13, 2000, Dayton Ventures, Inc. and Dayton Ventures LLC, affiliates of Kohlberg Kravis Roberts & Co. LLC (KKR), purchased a combination of trust preferred securities issued by a trust established by us, our voting preferred shares and warrants to purchase our common shares for an aggregate of $550 million. The trust preferred securities were redeemed at par in 2001 with proceeds of a new issuance of trust preferred securities and our Senior Notes. The 6.6 million Series B voting preferred shares had voting power not exceeding 4.9% of the total outstanding voting power of our voting securities and were purchased by Dayton Ventures LLC for an aggregate purchase price of $68 thousand. The warrants to purchase approximately 31.6 million common shares (representing approximately 19.9% of the common shares then outstanding) have a term of 12 years, an exercise price of $21 per share, and were purchased by Dayton Ventures LLC for an aggregate purchase price of $50 million. In connection with the March 13, 2000 transaction, we and KKR also entered into an agreement under which we paid KKR an annual management, consulting and financial services fee of $1.0 million. The agreement also stated that we would provide KKR with an opportunity to provide investment banking services on such terms as the parties may agree and at such time as any such services may be required. We also agreed to reimburse KKR and their affiliates for all reasonable expenses incurred in connection with the services provided under this agreement, including travel expenses and expenses of its counsel. We and KKR terminated this agreement on January 12, 2005. During December 2004 through January 2005, KKR initiated a series of agreements to transfer all of the warrants to an unaffiliated third party. This transferee subsequently transferred a large portion of the warrants to multiple unrelated third parties. In January 2005, as part of one of these transfers, KKR sold back to us all of the outstanding Series B voting preferred shares at par of $0.01 per share for $66 thousand.

Under the Securityholders and Registration Rights Agreement among us, DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures, Inc., KKR had the right to designate one person for election to, and one person to attend as a non-voting observer at all meetings of, the DPL and DP&L Boards of Directors for as long as Dayton Ventures LLC and its affiliates continue to beneficially own at least 12.64 million of our common shares, including shares issuable upon exercise of warrants. Scott M. Stuart, a director during fiscal 2003, and George R. Roberts, a non-voting observer, were the KKR designees in 2003 pursuant to this agreement. Mr. Stuart resigned from the Board and Mr. Roberts ceased to be a non-voting observer of the Board as of April 2004. As a result of the transfer of warrants from KKR to an unaffiliated third party during December 2004 through January 2005, KKR no longer owned any warrants or common stock. Accordingly, KKR no longer had the right to appoint one member and one observer to both DPL and DP&L Boards of Directors and the Securityholders and Registration Rights Agreement was amended to delete these, and other, rights.

In 1996, we entered into a consulting contract pursuant to which Peter H. Forster agreed to (i) serve, in a non-employee capacity, as Chairman of the Board of Directors of DPL, DP&L and MVE, and as Chairman of the Executive Committee of our Board of Directors and (ii) provide advisory and strategic planning consulting services. That contract became the subject of litigation after Mr. Forster resigned on May 16, 2004. (See Note 14 of Notes to Consolidated Financial Statements.)

In June 2001, our subsidiaries, MVE, of which Mr. Forster was Chairman, Miami Valley Development Company (MVDC) and Miami Valley Insurance Company, Inc. (MVIC), each entered into a management services agreement (the MSAs) with Valley Partners, Inc. (Valley) for the provision of ongoing oversight and management of each subsidiary’s financial asset holdings following a change of control of DPL or sale of the financial assets portfolio to an unaffiliated third party. Valley was a Florida corporation the sole stockholders, directors and officers of which were Mr. Forster and Ms. Muhlenkamp.

In October 2001, we and DP&L also entered into a Trustee Fee Agreement (the TFA) with Richard Chernesky, Richard Broock and Frederick Caspar, attorneys at Chernesky, Heyman & Kress P.L.L. Upon a change of control of DPL or DP&L, Messrs. Chernesky, Broock and Caspar would become the sole trustees of the master trusts for an annual fee of $500,000 and would succeed to all of the duties of our Compensation Committee under the compensation plans funded through the master trusts.

The MSAs, ASA and TFA (Valley Partners Agreements) were terminated by an agreement executed in January 2004, but effective as of December 15, 2003. The financial assets were not sold or transferred prior to such termination and therefore the agreements never became effective and no compensation was ever paid under them. Copies of the Valley Partners Agreements were filed as exhibits to our 2003 Form 10-K.

On April 26, 2004, we entered into a new Trustee Fee Agreement (New TFA) with Messrs. Chernesky, Broock and Caspar that would have become effective upon a change of control of DPL or DP&L. If the New TFA became effective, it provided that Messrs. Chernesky, Broock and Caspar would serve as the sole trustees of the master trusts in exchange for an annual fee of $250,000 during the New TFA’s term. A copy of the New TFA was filed as an exhibit to our 2003 Form 10-K. On October 14, 2004, at the request of DPL and DP&L, Messrs. Chernesky, Broock and Caspar submitted their resignations to us and DP&L.

On February 2 and 3, 2004, Mr. Koziar sent letters to Mr. Forster and Ms. Muhlenkamp purporting to amend their consulting and employment agreements to provide change of control protections regarding their MVE payments. In addition, on February 2, 2004, Mr. Koziar sent Mr. Forster a letter purporting to amend his consulting agreement to provide additional terms and to increase his compensation. However, none of those purported amendments had been approved by our Compensation Committee. Mr. Forster and Ms. Muhlenkamp resigned and Mr. Koziar retired on May 16, 2004.

We have initiated legal proceedings asserting breach of fiduciary duty and breach of contract by Messrs. Forster and Koziar and Ms. Muhlenkamp, and challenging the propriety and/or validity of certain contract terminations, purported amendments and agreements. (See Note 14 of Notes to Consolidated Financial Statements.)

16. Other Matters

Audit Committee Investigation and Related Matters

On March 10, 2004, our Corporate Controller, sent a memorandum (the Memorandum) to the Chairman of the Audit Committee of our Board of Directors (the Audit Committee). The Memorandum expressed the Corporate Controller's “concerns, perspectives and viewpoints” regarding financial reporting and governance issues within the Company.

On March 15, 2004, our Audit Committee retained the law firm of Taft, Stettinius & Hollister LLP (TS&H) to represent the Audit Committee in an independent review of each of the matters raised by the Memorandum. TS&H subsequently retained an accounting firm as a forensic accountant to assist in this review. On April 27, 2004, TS&H submitted a written report of its findings to the members of the Audit Committee (the Report). A copy of the Report was filed as an exhibit to our 2003 Form 10-K. While TS&H stated that it did not uncover and no person had indicated to it any uncorrected material inaccuracies in our books and records, it did, however, recommend further follow-up by the Audit Committee and improvements relating to disclosures, communication, access to information, internal controls and the culture of the Company in certain areas. Based upon information received after issuing the Report, TS&H revised its analysis and prepared a supplement to the Report, dated May 25, 2004 (the Supplement). A copy of the Supplement was filed as an exhibit to our 2003 Form 10-K.

Our Audit Committee considered the Report and Supplement at a meeting held on May 16, 2004. After its review and consideration, the Audit Committee recommended that the full Board of Directors accept the Report and the Supplement. At a meeting held on May 16, 2004, our Board of Directors accepted the Report and Supplement, including the findings and recommendations set forth therein. Mr. Forster and Ms. Muhlenkamp resigned and Mr. Koziar retired on May 16, 2004, and subsequently the Company has been involved in litigation with them (See Note 14 of Notes to Consolidated Financial Statements.) In addition, in 2004 corrective action was taken with regard to internal controls, process issues and tone at the top as identified in the Report.

Governmental and Regulatory Inquiries

On April 7, 2004, we received notice that the staff of the PUCO was conducting an investigation into the financial condition of DP&L as a result of previously disclosed matters raised by one of our executives during the 2003 year-end financial closing process (the Memorandum). On May 27, 2004, the PUCO ordered DP&L to file a plan of utility financial integrity that outlines the actions we have taken or would take to insulate DP&L utility operations and customers from our unregulated activities. DP&L was required to file this plan by March 2, 2005. On February 4, 2005, DP&L filed its protection plan with the PUCO and expressed its intention to continue to cooperate with the PUCO in their investigation. On March 29, 2005, the Ohio Consumers Counsel (OCC) filed comments with the PUCO on DP&L’s financial plan of integrity, requesting the PUCO continue the investigation and monitor DP&L’s progress toward implementation of its financial plan of integrity. On June 29, 2005, the PUCO closed its investigation, citing significant positive actions taken by DP&L including changes in our Board of Directors as well as executive management of DP&L, and that no apparent diminution of service quality has occurred because of the events that initiated the investigation.

exemption from the SEC. In light of the repeal of the ‘35 Act, effective February 8, 2006, and based upon the information previously provided to the staff of the SEC, this inquiry is moot.

On May 28, 2004, the U.S. Attorney’s Office for the Southern District of Ohio, assisted by the Federal Bureau of Investigation, notified us that it had initiated an inquiry involving matters connected to our internal investigation. We are cooperating with this investigation.

On or about June 24, 2004, the SEC commenced a formal investigation into the issues raised by the Memorandum. We are cooperating with the investigation.

On March 3, 2005, DP&L received a notice that the FERC had instituted an operational audit of DP&L regarding our compliance with our Code of Conduct within the transmission and generation areas. On October 7, 2005, the FERC issued its Findings and Conclusions, stating that we “generally complied with the [FERC] Standard of Conduct” except for three (3) areas, all of which were corrected to the satisfaction of the FERC prior to the issuance of these Findings and Conclusions.

Report of Independent Registered Public Accounting Firm

The Board of Directors
DPL Inc.:

We have audited the accompanying consolidated balance sheets of DPL Inc. and subsidiaries (the Company) as of December 31, 2005 and 2004, and the related consolidated statement of results of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2005. In connection with our audits of the consolidated financial statements, we have audited the consolidated financial statement schedule, “Schedule II - Valuation and Qualifying Accounts” for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements 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. 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 audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with United States generally accepted accounting principles. Also, in our opinion, the related financial statement schedules when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all materials respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2005, the Company adopted FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of Statement of Financial Accounting Standards No. 143".

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

/s/ KPMG LLP

KPMG LLP
Kansas City, Missouri
February 27, 2006

Report of Independent Registered Public Accounting Firm on Internal Controls

The Board of Directors
DPL Inc.:

We have audited management’s assessment, included in the Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that DPL Inc. and subsidiaries (the Company) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on

criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the company maintained, in all material respects, effective internal controls over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2005 and 2004, and the related consolidated statements of results of operations, shareholders’ equity, and cash flows for the three-year period ended December 31, 2005, and our report dated February 27, 2006, expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

KPMG LLP
Kansas City, Missouri
February 27, 2006

S e l e c t e d Q u a r t e r l y I n f o r m a t i o n (Unaudited)

	For the three months ended
	March 31,				June 30,				September 30,				December 31,
	2005		2004		2005		2004		2005		2004		2005 (b)			2004
Revenues	$	307.1	$	302.4	$	293.4	$	284.8	$	357.4	$	312.2	$	327.0		$	300.5
Operating Income	81.9		98.9		62.3		81.2		99.6		95.1		95.3			61.3

Earnings from continuing operations *(a)*	36.1		38.9		16.7		25.8		25.7		33.7		46.2			23.1
Earnings from discontinued operations, net of taxes	37.6		10.8		5.2		30.6		0.2		50.0		9.9			4.4
Cumulative effect of accounting change, net of taxes	—		—		—		—		—		—		(3.2		)	—
Net Income	$	73.7	$	49.7	$	21.9	$	56.4	$	25.9	$	83.7	$	52.9		$	27.5

Basic earnings per share of common stock:
Continuing operations	$	0.30	$	0.32	$	0.14	$	0.22	$	0.21	$	0.28	$	0.38		$	0.19
Discontinued operations	0.31		0.09		0.04		0.25		—		0.42		0.09			0.04
Cumulative effect of accounting change	—		—		—		—		—		—		(0.03		)	—
Total basic earnings per common share	$	0.61	$	0.41	$	0.18	$	0.47	$	0.21	$	0.70	$	0.44		$	0.23

Diluted earnings per share of common stock:
Continuing operations	$	0.28	$	0.32	$	0.13	$	0.21	$	0.20	$	0.28	$	0.36		$	0.19
Discontinued operations	0.30		0.09		0.04		0.25		—		0.41		0.08			0.03
Cumulative effect of accounting change	—		—		—		—		—		—		(0.03		)	—
Total diluted earnings per common share	$	0.58	$	0.41	$	0.17	$	0.46	$	0.20	$	0.69	$	0.41		$	0.22

Dividends paid per share	$	0.24	$	0.24	$	0.24	$	—	$	0.24	$	—	$	0.24		$	0.72

Common stock market price -High	$	26.77	$	20.77	$	27.67	$	19.77	$	28.12	$	20.64	$	28.01		$	25.36
-Low	$	24.27	$	17.60	$	24.08	$	17.21	$	26.70	$	19.02	$	24.55		$	20.30

(a) Earnings from continuing operations in the second and third quarter of 2005 include charges of $2.1 million and $59.1 million, respectively, for the early redemption of debt.

(b) Earnings from continuing operations in the fourth quarter of 2005 were $23.1 million more than the fourth quarter of 2004 primarily due to a $12.9 million reduction of interest expense, due largely to lower current year interest associated with the early redemption of debt, a $4.1 million increase in investment income, principally on short-term and tax-exempt investments, lower net margins of $13.5 million (higher revenues of $26.5 million offset by higher fuel and purchased power costs of $13.0 million), lower O&M expense of $17.1 million as a result of lower corporate costs, offset by higher taxes (the fourth quarter tax expense was reduced by state and tax credits of $11.5 million).

Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A – Controls and Procedures

Disclosure Controls and Procedures

Our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining our disclosure controls and procedures. These controls and procedures were designed to ensure that material information relating to us and our subsidiaries are communicated to the CEO and CFO. We evaluated these disclosure controls and procedures as of the end of the period covered by this report with the participation of our CEO and CFO. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic reports filed with the SEC.

There was no change in our internal control over financial reporting during the most recently completed fiscal period that has materially affected, or is reasonably likely to materially affect, internal control over reporting.

The following report is our report on internal control over financial reporting as of December 31, 2005.

Management’s Report on Internal Control Over Financial Reporting

We are responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including the CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on an evaluation under the framework in Internal Control - Integrated Framework, we concluded that our internal control over financial reporting was effective as of December 31, 2005.

Our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Item 9B – Other Information

None.

PART III

Item 10 - Directors and Executive Officers of the Registrant (Company)

The information required to be furnished pursuant to this item with respect to Directors of the Company will be set forth under captioned “Election of Directors” in the registrant’s proxy statement (the Proxy Statement) to be furnished to shareholders in connection with the solicitation of proxies by our Board of Directors for use at the 2006 Annual Meeting of Shareholders to be held on April 26, 2006 and is incorporated herein by reference.

The information required to be furnished pursuant to this item with respect to the identification of the Audit Committee, the Audit Committee financial expert and the registrant’s code of ethics will be set forth under the caption “Corporate Governance” in the Proxy Statement and is incorporated herein by reference.

Item 11 - Executive Compensation

The information required to be furnished pursuant to this item will be set forth under the caption “Executive Compensation” in the Proxy Statement and is incorporated herein by reference.

Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

The information required to be furnished pursuant to this item will be set forth under the captions “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Management” and “Equity Compensation Plan Information” in the Proxy Statement and is incorporated herein by reference.

Item 13 – Certain Relationships and Related Transactions

The information required to be furnished pursuant to this item will be set forth under the caption “Certain Relationships and Related Transactions” in the Proxy Statement and is incorporated herein by reference.

Item 14 – Principal Accountant Fees and Services

The information required to be furnished pursuant to this item will be set forth under the caption “Audit and Non-Audit Fees” in the Proxy Statement and is incorporated herein by reference.

PART IV

Item 15 - Exhibits and Financial Statement Schedules

				Page No.
(a)	The following documents are filed as part of this report:

1.			Financial Statements

Consolidated Statements of Results of Operations for each of the three years in the period ended December 31, 2005				48
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2005				49
Consolidated Balance Sheets at December 31, 2005 and 2004				50
Consolidated Statement of Shareholders’ Equity for each of the three years in the period ended December 31, 2005				52
Notes to Consolidated Financial Statements				53
Report of Independent Registered Public Accounting Firm				90
Report of Independent Registered Public Accounting Firm on Internal Controls				91

2.		Financial Statement Schedule

For each of the three years in the period ended December 31, 2005:

Schedule II – Valuation and Qualifying Accounts				105

The information required to be submitted in Schedules I, III, IV and V is omitted as not applicable or not required under rules of Regulation S-X.

3. Exhibits

Exhibits are incorporated by reference as described unless otherwise filed as set forth herein.

The exhibits filed as a part of this Annual Report on Form 10-K are:

		Location

2(a)	Copy of Asset Purchase Agreement, dated December 14, 1999, between The Dayton Power and Light Company, Indiana Energy, Inc., and Number-3CHK, Inc.		Exhibit 2 to Report on Form 10-Q for the quarter ended September 30, 2000 (File No. 1-9052)

3(a)	Copy of Amended Articles of Incorporation of DPL Inc. dated September 25, 2001		Exhibit 3 to Report on Form 10-K/A for the year ended December 31, 2001 (File No. 1-2385)

3(b)	Regulations of DPL Inc.		Exhibit 3(b) to Form 8-K filed on May 3, 2004 (File No. 1-9052)

4(a)	Copy of Composite Indenture dated as of October 1, 1935, between DP&L and The Bank of New York, Trustee with all amendments through the Twenty-Ninth Supplemental Indenture	Exhibit 4(a) to Report on Form 10-K for the year ended December 31, 1985 (File No. 1-2385)

4(b)	Copy of Forty-First Supplemental Indenture dated as of February 1, 1999, between DP&L and The Bank of New York, Trustee	Exhibit 4(m) to Report on Form 10-K for the year ended December 31, 1998 (File No. 1-2385)

4(c)	Copy of Forty-Second Supplemental Indenture dated as of September 1, 2003, between DP&L and The Bank of New York, Trustee	Exhibit 4(r) to Report on Form 10-K for the year ended December 31, 2003 (File No. 1-2385)

4(d)	Copy of Forty-Third Supplemental Indenture dated as of August 1, 2005, between DP&L and The Bank of New York, Trustee	Exhibit 4.4 to Report on Form 8-K filed on August 24, 2005 (File No. 1-2385)

4(e)	Copy of Rights Agreement between DPL Inc. and Equiserve Trust Company, N.A.	Exhibit 4 to Report on Form 8-K dated September 25, 2001 (File No. 1-9052)

4(f)	Copy of Securities Purchase Agreement dated as of February 1, 2000 by and among DPL Inc. and DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures Inc. and certain exhibits thereto	Exhibit 99(b) to Schedule TO-I dated February 4, 2000 (File No. 1-9052)

4(g)	Amendment to Securities Purchase Agreement dated as of February 24, 2000 among DPL Inc., DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures, Inc.	Filed herewith as Exhibit 4(g)

4(h)	Copy of Warrant Form initially issued as of February 1, 2000	Filed herewith as Exhibit 4(h)

4(i)	Securityholders and Registration Rights Agreement dated as of February 1, 2000 among DPL Inc., DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures, Inc.	Filed herewith as Exhibit 4(i)

4(j)	Amendment to Securityholders and Registration Rights Agreement, dated August 24, 2001 among DPL Inc., DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures, Inc.	Filed herewith as Exhibit 4(j)

4(k)	Amendment to Securityholders and Registration Rights Agreement, dated December 6, 2004 among DPL Inc., DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures, Inc.	Filed herewith as Exhibit 4(k)

4(l)	Amendment to Securityholders and Registration Rights Agreement, dated January 12, 2005 among DPL Inc., DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures, Inc.	Filed herewith as Exhibit 4(l)

4(m)	Copy of Credit Agreement dated as of June 1, 2004 between The Dayton Power and Light Company, KeyBank National Association (as administrative agent and lead arranger) and the lending institutions named therein	Exhibit 4(ee) to Report on Form 10-K for the year ended December 31, 2003 (File No. 1-2385)

4 (n)	Copy of Credit Agreement dated as of May 31, 2005 between The Dayton Power and Light Company, KeyBank National Association (as administrative agent and lead arranger) and the lending institutions named therein	Exhibit 10.1 to Form 8-K filed on June 28, 2005 (File No. 1-9052)

4(o)	Officer’s Certificate of DPL Inc. establishing $175 million Senior Note due 2009, dated March 25, 2004	Exhibit 4.1 to Form 8-K, filed on March 29, 2004 (File No. 1-9052)

4(p)	Exchange and Registration Rights Agreement dated March 25, 2004 between DPL Inc. and the purchasers	Exhibit 4.2 to Form 8-K, filed on March 29, 2004 (File No. 1-9052)

4(q)	Indenture dated as of March 1, 2000 between DPL Inc. and Bank One Trust Company, National Association	Exhibit 4(b) to Registration Statement No. 333-37972

4(r)	Officer’s Certificate of DPL Inc. establishing exchange notes, dated March 1, 2000	Exhibit 4(c) to Registration Statement No. 333-37972

4(s)	Exchange and Registration Rights Agreement dated as of August 24, 2001 between DPL Inc., Morgan Stanley & Co., Incorporated, Bank One Capital Markets, Inc., Fleet Securities, Inc. and NatCity Investments, Inc.	Exhibit 4(a) to Registration Statement No. 333-74568

4(t)	Officer’s Certificate of DPL Inc. establishing exchange notes, dated August 31, 2001	Exhibit 4(c) to Registration Statement No. 333-74568

4(u)	Indenture dated as of August 31, 2001 between DPL Inc. and The Bank of New York, Trustee	Exhibit 4(a) to Registration Statement No. 333-74630

4(v)	First Supplemental Indenture dated as of August 31, 2001 relating to the subordinated debentures between DPL Inc. and The Bank of New York	Exhibit 4(b) to Registration Statement No. 333-74630

4(w)	Amended and Restated Trust Agreement dated as of August 31, 2001 relating to DPL Capital Trust II, the Capital Securities and the Common Securities among DPL Inc., the depositor, The Bank of New York, as property trustee, The Bank of New York (Delaware), as Delaware trustee, and Allen M. Hill and Stephen F. Koziar, Jr., as administrative trustees, and the holders, from time	Exhibit 4(c) to Registration Statement No. 333-74630

	to time of undivided beneficial interests in DPL Capital Trust II

4(x)	Exchange and Registration Rights Agreement dated as of August 24, 2001 among DPL Inc., DPL Capital Trust II and Morgan Stanley & Co., Incorporated	Exhibit 4(d) to Registration Statement No. 333-74630

10(a)*	Copy of Directors’ Deferred Stock Compensation Plan amended December 31, 2000	Exhibit 10(a) to Report on Form 10-K for the year ended December 31, 2000 (File No. 1-9052)

10(b)*	Copy of Directors’ 1991 Amended Deferred Compensation Plan as amended through December 31, 2000	Exhibit 10(b) to Report on Form 10-K for the year ended December 31, 2000 (File No. 1-9052)

10(c)*	Amendment No. 1 dated as of December 7, 2004 to Directors’ 1991 Amended Deferred Compensation Plan as amended through December 31, 2000	Filed herewith as Exhibit 10(c)

10(d)*	Copy of Management Stock Incentive Plan amended December 31, 2000	Exhibit 10(c) to Report on Form 10-K for the year ended December 31, 2000 (File No. 1-9052)

10(e)*	Amendment No. 1 dated as of December 7, 2004 to Management Stock Incentive Plan amended December 31, 2000	Filed herewith as Exhibit 10(e)

10(f)*	Copy of Key Employees Deferred Compensation Plan amended December 31, 2000	Exhibit 10(d) to Report on Form 10-K for the year ended December 31, 2000 (File No. 1-9052)

10(g)*	Amendment No. 1 dated as of December 7, 2004 to Key Employees Deferred Compensation Plan amended December 31, 2000	Filed herewith as Exhibit 10(g)

10(h)*	Copy of Supplemental Executive Retirement Plan amended February 1, 2000	Exhibit 10(e) to Report on Form 10-K for the year ended December 31, 2003 (File No. 1-2385)

10(i)*	Amendment No. 1 dated as of December 7, 2004 to Supplemental Executive Retirement Plan amended February 1, 2000	Filed herewith as Exhibit 10(i)

10(j)*	Copy of Stock Option Plan	Exhibit 10(f) to Report on Form 10-K for the year ended December 31, 2000 (File No. 1-9052)

10(k)*	2003 Long-Term Incentive Plan of DPL Inc. dated as of January 20, 2003	Exhibit 10(aa) to Report on Form 10-K for the year ended December 31,2003 (File No. 1-9052)

10(l)*	Summary of Executive Life Insurance Plan	Filed herewith as Exhibit 10(l)

10(m)*	Summary of Executive Medical Insurance Plan	Filed herewith as Exhibit 10(m)

10(n)*	Amended and Restated Employment Agreement dated as of August 31, 2005 effective as of January 1, 2005 between DPL Inc., The Dayton Power and Light Company and Robert D. Biggs	Exhibit 10.1 to Report on Form 8-K filed on September 2, 2005 (File No. 1-9052

10(o)*	Letter Agreement dated as of September 20, 2004 and Management Stock Option Agreement, as amended, dated as of October 5, 2004, between DPL Inc. and Robert D. Biggs	Exhibits 10.2 and 10.3 to Report on Form 8-K filed on October 8, 2004 (File No. 1-9052)

10(p)*	Management Stock Option Agreement dated as of August 31, 2005 between DPL Inc. and Robert D. Biggs	Exhibit 10.2 to Report on Form 8-K filed on September 2, 2005 (File No. 1-9052)

10(q) *	Employment agreement dated as of December 21, 2004 between DPL Inc., The Dayton Power and Light Company and James V. Mahoney	Exhibit 10.1 to Form 8-K filed on December 28, 2004 (File No. 1-9052)

10(r)*	Employment agreement dated as of January 3, 2003, between DPL Inc., The Dayton Power and Light Company and James V. Mahoney	Exhibit 10(j) to Report on Form 10-K for the year ended December 31, 2003 (File No. 1-9052)

10(s)*	Change of Control Agreement dated as of January 3, 2003, between DPL Inc., The Dayton Power and Light Company and James V. Mahoney and Management Stock Option Agreement dated January 3, 2003 between DPL Inc. and James V. Mahoney	Exhibit 10(o) to Report on Form 10-K for the year ended December 31, 2003 (File No.1-9052)

10 (t)*	Employment agreement dated as of December 14, 2004 between DPL Inc., The Dayton Power and Light Company and John J. Gillen	Exhibit 10.2 to Form 8-K filed on December 28, 2004 (File No. 1-9052)

10(u)*	Management Stock Option Agreement dated as of December 29, 2004 between DPL Inc. and John J. Gillen	Filed herewith as Exhibit 10(u)

10(v)*	Employment agreement dated as of September 17, 2003, between DPL Inc. and W. Steven Wolff	Exhibit 10(k) to Report on Form 10-K for the year ended December 31, 2003 (File No.1-9052)

10(w)*	Change of Control Agreement dated as of September 10, 2004, between DPL Inc., The Dayton Power and Light Company and W. Steven Wolff	Exhibit 10(dd) to Report on Form 8-K filed September 23, 2004 (File No. 1-9052)

10(x)*	Employment agreement dated as of December 17, 2003,	Exhibit 10(l) to Report on

100

	between DPL Inc. and Patricia K. Swanke	Form 10-K for the year ended December 31, 2003 (File No.1-9052)

10(y)*	Change of Control Agreement dated as of July 1, 2004 between DPL Inc., The Dayton Power and Light Company and Patricia K. Swanke and Management Stock Option Agreement dated as of January 1, 2001 between DPL Inc. and Patricia K. Swanke	Exhibit 10(s) to Report on Form 10-K for the year ended December 31, 2004 (File No. 1-9052)

10(z)*	Employment Agreement and Change of Control Agreement dated as of September 17, 2004 between DPL Inc., The Dayton Power and Light Company and Gary Stephenson	Exhibit 10(ee) to Report on Form 8-K filed on September 23, 2004 (File No. 1-9052)

10(aa)*	Employment agreement dated as of June 9, 2003, as amended by attached letter dated October 18, 2004, between DPL Inc., The Dayton Power and Light Company and Miggie E. Cramblit	Exhibit 10(gg) to Report on Form 10-K for the year ended December 31, 2003 (File No. 1-9052)

10(bb)*	Change of Control Agreement dated as of December 15, 2000 between DPL Inc., The Dayton Power and Light Company and Arthur G. Meyer	Filed herewith as Exhibit 10(bb)

10(cc)*	Management Stock Option Agreement dated as of January 1, 2001 between DPL Inc. and Arthur G. Meyer	Filed herewith as Exhibit 10(cc)

10(dd)*	Letter dated October 28, 1998 from DPL Inc. awarding lifetime medical benefits to Arthur G. Meyer	Filed herewith as Exhibit 10(dd)

10(ee)*	Letter dated November 26, 1997 from DPL Inc. awarding executive life insurance benefits to Arthur G. Meyer	Filed herewith as Exhibit 10(ee)

10(ff)	Purchase and Sale Agreement dated as of February 13, 2005 between MVE, Inc., Miami Valley Insurance Company and AlpInvest/Lexington 2005, LLC	Exhibit 10.1 to Form 8-K filed on February 18, 2005 (File No. 1-9052)

18	Copy of preferability letter relating to change in accounting for unbilled revenues from Price Waterhouse LLP	Exhibit 18 to Report on Form 10-K for the year ended December 31, 1987 (File No. 1-9052)

21	List of Subsidiaries of DPL Inc.	Filed herewith as Exhibit 21

23	Consent of KPMG LLP	Filed herewith as Exhibit 23

31(a)	Certification of Chief Executive Officer pursuant to Rule 13a–14(a)/15d-14(a) of the Securities Exchange Act of 1934	Filed herewith as Exhibit 31(a)

31(b)	Certification of Chief Financial Officer pursuant to Rule 13a–14(a)/15d–14(a) of the Securities Exchange Act of 1934	Filed herewith as Exhibit 31(b)

32(a)	Certification of Chief Executive Officer pursuant to	Filed herewith as

101

	18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Exhibit 32(a)

32(b)	Certification of Chief Financial Officer pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(b)

99(a)	Report of Taft, Stettinius & Hollister LLP, dated April 26, 2004	Exhibit 99(a) to Report on Form 10-K for the year ended December 31, 2003 (File No. 1-9052)

99(b)	Supplement to the April 26, 2004 Report of Taft, Stettinius & Hollister LLP, dated May 15, 2004	Exhibit 99(b) to Report on Form 10-K for the year ended December 31, 2003 (File No. 1-9052)

99(c)	Complaint filed in Montgomery County Court of Common Pleas, Montgomery County, Ohio – DPL Inc., The Dayton Power and Light Company and MVE, Inc. v. Peter H. Forster, Caroline E. Muhlenkamp and Stephen F. Koziar, Jr.	Exhibit 99(d) to Report on Form 10-K for the year ended December 31, 2003 (File No. 1-9052)

*Management contract or compensatory plan.

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

102

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	DPL Inc.

February 27, 2006
By:	/s/ James V. Mahoney
	James V. Mahoney President and Chief Executive Officer (principal executive officer)

103

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ R. D. Biggs	Director and Executive Chairman	February 27, 2006
(R. D. Biggs)


/s/ P. R. Bishop	Director	February 27, 2006
(P. R. Bishop)


/s/ B. S. Graham	Director	February 27, 2006
(B. S. Graham)


/s/ E. Green	Director	February 27, 2006
(E. Green)


/s/ G.E. Harder	Director	February 27, 2006
(G. E. Harder)


/s/ W A. Hillenbrand	Director and Vice-Chairman	February 27, 2006
(W A. Hillenbrand)

/s/ L.L. Lyles
(L. L. Lyles)	Director	February 27, 2006


/s/ J. V. Mahoney	Director, President and Chief	February 27, 2006
(J. V. Mahoney)	Executive Officer (principal executive officer)


/s/ N.J. Sifferlen
(N.J. Sifferlen)	Director	February 27, 2006


/s/ J. J. Gillen	Senior Vice President and	February 27, 2006
(J. J. Gillen)	Chief Financial Officer (principal financial and principal accounting officer)


/s/ D. L. Thobe	Corporate Controller	February 27, 2006
(D. L. Thobe)

104

Schedule II

DPL Inc.

VALUATION AND QUALIFYING ACCOUNTS

For the years ended December 31, 2003-2005

$ in thousands

Description	Balance at Beginning of Period		Additions		Deductions (1)		Balance at End of Period

2005:
Deducted from accounts receivable—

Provision for uncollectible accounts	$	1,085	$	3,582	$	3,623	$	1,044

2004:
Deducted from accounts receivable—

Provision for uncollectible accounts	$	6,003	$	3,371	$	8,289	$	1,085

2003:
Deducted from accounts receivable—

Provision for uncollectible accounts	$	11,094	$	3,672	$	8,763	$	6,003

(1) Amounts written off, net of recoveries of accounts previously written off.

105

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

DPL (DPL) 10-K2005 FY Annual report

Content analysis

Schedule II – Valuation and Qualifying Accounts

105