-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, U3Lyz8Ruyy1MeVBYmnLqZWXQefRc6hAS489SFvpuDgZiPIjXGPbUVx60H/iqX6xE YAWsgWLOiw5TpLa3QIEYfw== 0001104659-06-014678.txt : 20060307 0001104659-06-014678.hdr.sgml : 20060307 20060307171218 ACCESSION NUMBER: 0001104659-06-014678 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20051231 FILED AS OF DATE: 20060307 DATE AS OF CHANGE: 20060307 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DAYTON POWER & LIGHT CO CENTRAL INDEX KEY: 0000027430 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 310258470 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-02385 FILM NUMBER: 06670788 BUSINESS ADDRESS: STREET 1: 1065 WOODMAN DRIVE CITY: DAYTON STATE: OH ZIP: 45432 BUSINESS PHONE: 9372246000 MAIL ADDRESS: STREET 1: 1065 WOODMAN DRIVE CITY: DAYTON STATE: OH ZIP: 45432 10-K 1 a06-2289_110k.htm ANNUAL REPORT PURSUANT TO SECTION 13 AND 15(D)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

SECURITIES EXCHANGE ACT OF 1934

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: 1-2385

THE DAYTON POWER AND LIGHT COMPANY

(Exact name of registrant as specified in its charter)

OHIO		31-0258470
(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
None

Outstanding at February 28, 2006,

all of which were held by DPL Inc.

41,172,173

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 o

Accelerated filer o

Non-accelerated filer ý

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 none.

DOCUMENTS INCORPORATED BY REFERENCE

None.

THE DAYTON POWER AND LIGHT COMPANY

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	15
Item 1b	Unresolved Staff Comments	19
Item 2	Properties	20
Item 3	Legal Proceedings	20
Item 4	Submission of Matters to a Vote of Security Holders	22

	Part II
Item 5	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	22
Item 6	Selected Financial Data	23
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	37
Item 8	Financial Statements and Supplementary Data	38
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	73
Item 9A	Controls and Procedures	73
Item 9B	Other Information	73

	Part III
Item 10	Directors and Executive Officers of the Registrant	74
Item 11	Executive Compensation	76
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	87
Item 13	Principal Accountant Fees and Services	88


	Part IV
Item 15	Exhibits and Financial Statement Schedules	90

	Other
	Signatures	97
	Schedule II Valuation and Qualifying Accounts	99
	Subsidiaries of DP&L

Available Information

The Dayton Power and Light Company (DP&L, the Company, we, us, our, or ours unless the context indicates otherwise) files current, annual and quarterly reports, 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 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 DP&L Investor Relations, 1065 Woodman Drive, Dayton, Ohio 45432.

PART I

Item 1 – Business

THE DAYTON POWER AND LIGHT COMPANY

We are a public utility incorporated in 1911 under the laws of Ohio and are a wholly-owned subsidiary of DPL Inc. (DPL). Our executive offices are located at 1065 Woodman Drive, Dayton, Ohio 45432 - telephone (937) 224-6000.

We sell electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for our 24-county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. We also purchase retail peak load requirements from DPL Energy, LLC (DPLE), a wholly-owned subsidiary of DPL. Principal industries served include automotive, food processing, paper, plastic manufacturing and defense. Our sales reflect the general economic conditions and seasonal weather patterns of the area. In addition, we sell any excess energy and capacity into the wholesale market.

We have one significant subsidiary, DPL Finance Company, Inc., which is wholly-owned and provides financing to us and other affiliated companies. We conduct our principal business in one business segment - Electric.

The Company employed 1,368 persons as of December 31, 2005, of which 1,134 were full-time employees and 234 were part-time employees.

All of our outstanding shares of common stock are held by DPL, which became the Company’s corporate parent, effective April 21, 1986.

SIGNIFICANT DEVELOPMENTS

Rate Stabilization Surcharge

On April 4, 2005, we 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, we entered into a settlement agreement that extended our 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 us. Major components include: 3%, 2% and 2.5% annual wage increases over three years, improvements to the pension and 401(k) programs, increases in our 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 our illness benefits. On December 31, 2005, 760 employees were members of Local 175.

Governmental and Regulatory Inquiries

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

On March 3, 2005, we received a notice that the Federal Energy Regulatory Commission (FERC) had instituted an operational audit of us regarding our 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 we “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.

COMPETITION AND REGULATION

We have historically operated in a rate-regulated environment providing electric generation and energy delivery, consisting of transmission and distribution services, as a single product to our retail customers. Prior to the legislation discussed below, we did not have retail competitors in our 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.

We 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, we 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 us 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.

On April 4, 2005, we 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, we entered into a settlement agreement that extended our rate stabilization period through December 31, 2010. During this time, we 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:

As a part of the MDP Stipulation, we 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 our 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, we 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. We submitted comments in March 2003. The PUCO issued final rules on December 23, 2003. Under our RSS Stipulation discussed above, these rules will not affect us 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 our 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 our service territory in 2005. In addition, several communities in our 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 our billing services. Previously, on December 16, 2003, a complaint was filed at the PUCO alleging that we had established improper barriers to competition. On October 13, 2004, the parties reached a settlement on the pricing of our billing services that we will charge CRES providers. Additionally, on October 19, 2004, we entered into a settlement that resolves all matters in the barrier to competition complaint. This settlement provides that we will modify the manner in which customer partial payments are applied to billing charges and we will no longer offer to purchase the receivables of CRES providers who operate in our certified territory. On February 2, 2005, the PUCO issued an Order approving both settlements with minor modifications. This Order gives us 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, we 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 us in Mercer County Common Pleas Court relating to billing costs that may be charged to residential customers. We 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, we filed an application requesting the PUCO grant us 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, we filed updated schedules in support of our 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.

Like other electric utilities and energy marketers, we may sell or purchase electric products on the wholesale market. We compete with other generators, power marketers, privately and municipally-owned electric utilities, and rural electric cooperatives when selling electricity. Our ability to sell this electricity will depend on how our 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, we successfully integrated our 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 our 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.

We provide transmission and wholesale electric service to twelve municipal customers in our service territory, which distributes electricity principally within their incorporated limits. We also maintain 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. Our contract with one municipality expired in February 2005, creating reduced future generation sales to municipalities.

As of December 31, 2004, we had invested a total of approximately $18.0 million in our efforts to join an RTO. On March 8, 2005, we, 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 our customers. On October 26, 2004, we filed an application with the PUCO for authority to modify our accounting procedures to defer collection of this PJM administrative fee, plus carrying charges, until such time we obtained the authority to adjust our rates to recover this cost from customers (i.e., after January 1, 2006). On June 1, 2005, the PUCO authorized us 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, we 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 us, may be unjust, unreasonable, or unduly discriminatory or preferential. We are 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, we began receiving these FERC ordered transitional payments and have received over $23 million of SECA collections, net of SECA charges, through December 2005. Our 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 our 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 us, address the justness and reasonableness of the current rate design. On November 22, 2005, we, along with ten other transmission owners, filed in support of PJM’s existing rate design. We cannot determine what effect, if any, the outcome of this proceeding may have on our 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 we 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; and (4) require that fifty 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 us is unclear at this time.

On March 3, 2005, we received a notice that the FERC had instituted an operational audit of us 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’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, we received notice that the staff of the PUCO was conducting an investigation into our financial condition as a result of financial reporting and governance issues raised by the Memorandum. On May 27, 2004, the PUCO ordered us to file a plan of utility financial integrity that outlines the actions DPL has taken or will take to insulate our utility operations and customers from DPL’s unregulated activities. We were required to file this plan by March 2, 2005. On February 4, 2005, we filed our protection plan with the PUCO and expressed our intention to continue to cooperate with the PUCO in their investigation. On March 29, 2005, the OCC filed comments with the PUCO on our financial plan of integrity, requesting the PUCO continue the investigation and monitor our progress toward implementation of our financial plan of integrity. On June 29, 2005, the PUCO closed its investigation, citing significant positive actions taken by us including changes in the Board of Directors as well as our executive management, and that no apparent diminution of service quality has occurred because of the events that initiated the investigation.

CONSTRUCTION ADDITIONS

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 $745 million in capital projects, approximately 61% 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 3,291 MW. Of this capacity, approximately 2,856 MW or 87% is derived from coal-fired steam generating stations and the balance of approximately 435 MW or 13% 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. Our remaining steam generating capacity (approximately 365 MW) is derived from a generating station owned solely by us. Additionally, we, CG&E and CSP own as tenants in common, 884 circuit miles of 345,000-volt transmission lines. We have several interconnections with other companies for the purchase, sale and interchange of electricity.

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

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

Approximate Summer

Operating

MW Rating

Station

Ownership*

Company

Location

DP&L 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

Total approximate summer generating capacity

3,291

7,898

*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 our 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 1.84¢ in 2005, 1.53¢ in 2004 and 1.29¢ 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 us, 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, our power generation and delivery operations have generated less revenue and income when weather conditions are warmer in the winter and cooler in the summer.

RATE REGULATION AND GOVERNMENT LEGISLATION

Our sales to retail customers are subject to rate regulation by the PUCO. Our 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

Our operations, including our 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, we have ongoing programs and activities underway at these facilities to comply, or to determine compliance, with such existing, new and/or proposed regulations and legislation.

We have 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. We record 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, we accrue 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. We evaluate the potential liability related to probable losses quarterly and may revise our 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 us 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. We were 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 us (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 Stuart Generating Station (co-owned by us, CG&E, and CSP and operated by us) 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 us 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, CSP, and us), 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). We believe the allegations are meritless and believe 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, CSP, and us). We believe 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 emissions 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 the 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. We own and/or operate a number of facilities in counties designated as nonattainment with the ozone national ambient air quality standard. We do not know at this time what future regulations may be imposed on our 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. We 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 we operate and/or own generating facilities. On March 4, 2005, we 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. We cannot determine the outcome of the petition for review or the effect such Ohio EPA regulations will have on our 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. We anticipate 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, we 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, we 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, we 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, we received a special notice letter inviting us to enter into negotiations with USEPA to conduct the RI/FS. Although the information available to us does not demonstrate that we contributed hazardous substances to the site, we will seek from USEPA a de minimis settlement at the site. Should USEPA pursue a civil action, we will vigorously challenge it.

THE DAYTON POWER AND LIGHT COMPANY

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	$	442,238
Commercial	247,912		239,952		243,474
Industrial	126,506		128,059		160,801
Other retail	81,877		80,623		81,644
Other miscellaneous revenues	10,317		15,914		13,053
Total retail	944,838		913,959		941,210

Wholesale	257,632		260,341		242,232

RTO ancillary revenues	74,419		17,905		—

Total	$	1,276,889	$	1,192,205	$	1,183,442

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.

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 us, have worked out plans to provide market-based pricing for generation service, but also to stabilize those rates for several years. What we 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 our 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 our 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, we 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 our 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 our 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 our service territory and could begin to offer better prices than they do now. This could result in more switching by our customers and a further loss by us of our generation business.

• Governmental Aggregation Programs

Another possible way in which we 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 our 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.

Our ability to increase our rates to recover increased costs is limited.

As a result of the failure of the market to develop as anticipated, we have proposed to stabilize our 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. Our distribution rates will be unchanged through December 31, 2008 and our generation rates will be maintained through December 31, 2008. Although the PUCO has approved several riders that will permit us 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 our generation service to CRES providers could affect our ability to recover those costs. Moreover, we will not be able to adjust our rates during the rate stabilization period for increases in other expenses or to recover capital expenditures.

We have agreed to provide service at pre-determined rates through December 31, 2010, which limits our ability to pass through our costs to customers.

We have 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 our 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, we extended our commitment to maintain pre-determined rates for generation through December 31, 2010, and in exchange are 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 $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 we are allowed to charge may or may not match our expenses at any given time. Therefore, during this period (or possibly earlier by order of the PUCO), and, thereafter, while we 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. We have historically maintained our rates at consistent levels since 1994 when the last phase of our last traditional rate case was implemented. However, as we operate under our PUCO-approved RSS Stipulation, there can be no assurance that we 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 our plants or other properties.

There are uncertainties relating to the ultimate development of Regional Transmission Organizations (RTOs), including the PJM to which we have given control of our transmission functions.

On October 1, 2004, we gave PJM control of our transmission functions and fully integrated into PJM. Problems or delays that may arise in the formation and operation of RTOs may restrict our ability to sell power produced by our 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 our costs and revenues. While RTO rates are designed to be revenue neutral, our revenues from customers to whom we currently provide transmission services could decrease. We will incur fees and increased costs to participate in an RTO, we may be limited with respect to the price at which power may be offered for sale from certain generating units, and we may be required to expand our transmission system according to decisions made by an RTO rather than by our internal planning process. Because the RTO market rules are continuing to evolve, it remains unclear which companies will be participating in the various regional power markets, or how RTOs will develop or what region they will cover, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have on 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 our inventory of coal and may cause us to purchase higher priced coal on the spot market. When the failure is for a short period of time, we can absorb the irregularity due to existing inventory levels. However, we cannot tolerate an extended contract breach by a coal supplier who supplies a substantial portion of a power plant under our operation. 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, 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 our 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.

Changes in our customer base, including aggregation, could lead to the entrance of competitors in our marketplace 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.

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.

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. 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 of our property and plant is subject to the lien of the mortgage securing our 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, DPL 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, DPL 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, DPL 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, DPL, 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 we, DPL, 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.

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. (See Note 13 of Notes to Consolidated Financial Statements.)

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

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.

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 us by letter alleging we 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, we and the OFCCP entered into a Conciliation Agreement whereby we agreed to distribute approximately $0.2 million in compensation to certain affected applicants. We have 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 us for injuries he sustained while working at a 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, we 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 our favor, finding it owed no prejudgment interest to the Plaintiff.

Additional information relating to legal proceedings involving DP&L is contained in Item 1 –ENVIRONMENTAL CONSIDERATIONS, and Item 8 – Note 11 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 us. AMP-Ohio alleges it has a right to receive certain capacity credits. We disagree with this position and have 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

Our common stock is held solely by our parent DPL and, as a result, is not listed for trading on any stock exchange.

As long as any preferred stock is outstanding, our 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 our net income available for dividends on our common stock subsequent to December 31, 1946, plus $1.2 million. As of year-end, all of our earnings reinvested in the business were available for common stock dividends. We expect all 2006 earnings reinvested in our business to be available for our common stock dividends, payable to DPL.

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

Additional information concerning dividends paid on DP&L preferred stock is set forth in Item 8 - Selected Quarterly Information and Financial and Statistical Summary.

Information regarding DP&L’s 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.

Item 6 - Selected Financial Data

Selected financial data is set forth in Item 8 – Selected Quarterly Information Financial and Statistical Summary.

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 the world’s largest competitive wholesale electricity market, 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 us.

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.

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	$	944.9		914.0			941.2
Wholesale	257.6			260.3			242.2
RTO ancillary (a)	74.4			17.9			—
Total Revenues	$	1,276.9		$	1,192.2		$	1,183.4
Less: Fuel	317.9			257.0			226.2
Purchased power (b)	147.1			116.4			92.7
Net margins (c)	$	811.9		$	818.8		$	864.5

Net margins as a percentage of revenues	63.6		%	68.7		%	73.1		%

Operating income	$	382.6		$	369.4		$	394.8

(a) Revenues include 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 $0 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 $1,276.9 million for 2005 compared to $1,192.2 million for 2004, reflecting an increase of $84.7 million. This increase was primarily the result of increased retail sales volume, higher average rates for wholesale and retail revenues, and ancillary revenues associated with participation in PJM that was partially offset by lower wholesale sales volume. Retail revenues increased $30.9 million, primarily resulting from increased sales volume of $28.9 million and $7.6 million in higher average rates, partially offset by $5.6 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 $2.7 million, primarily related to a $71.6 million decline in sales volume that was nearly offset by a $68.9 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 our transmission assets, regulation services, reactive supply and operating reserves.

Revenues increased $8.8 million to $1,192.2 million in 2004 compared to $1,183.4 million in 2003. Wholesale revenues increased $18.1 million or 7% in 2004 resulting from higher average market rates. The increase in wholesale revenues was largely offset by decreases in retail revenues of $27.2 or 3% in 2004 that reflected lower average rates, primarily driven from industrial customers buying generation from alternative suppliers. 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 $811.9 million decreased by $6.9 million from $818.8 million for 2004. As a percentage of total revenues, net margin decreased by 5.1 percentage points to 63.6% from 68.7%. This decline is primarily the result of a $91.6 million increase in fuel and purchased power costs, offset by an $84.7 increase in revenues (see discussion of revenue variance above). Fuel costs, which include coal, gas, oil and emission allowance costs, increased by $60.9 million for 2005 compared to the same period in 2004 primarily resulting from higher average fuel prices as well as an increased volume of electric generation. Purchased power costs increased by $30.7 million for 2005 compared to the same period in 2004 primarily resulting from increased charges of $36.2 million associated with moving power across PJM (we did not participate in PJM until October 2004) as well as increases related to higher average market prices, partially offset by lower purchased power volume.

For 2004, net margin of $818.8 million decreased by $45.7 million from $864.5 million for 2003. This decline in net margin was primarily the result of a lower volume of retail sales and increased fuel and purchased power costs, partially offset by a slight increase in wholesale sales and ancillary PJM revenues. As a percentage of total revenues, net margin decreased by 4.4 percentage points to 68.7% in 2004 from 73.1% in 2003. This decrease in net margin was primarily attributable to higher fuel and purchased power costs per kWh. Fuel costs increased by $30.8 million or 14% in 2004 compared to 2003 primarily related to rising prices in the coal market. Purchased power costs

including PJM costs increased by $23.7 million or 26% 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	$	4.1		$	13.1
Pension and benefits	0.6			7.7
Reduction in capitalized insurance and claims costs	(0.3		)	2.4
PJM Administrative fees	(1.6		)	2.9
Sarbanes-Oxley compliance and external/internal audit fees	(3.5		)	6.4
Executive and management compensation	(10.2		)	(13.8		)
Directors’ & Officers’ liability insurance	(14.8		)	6.1
Other – net (decrease) / increase	(0.4		)	1.9
Total	$	(26.1	)	$	26.7

Operation and maintenance expense decreased $26.1 million or 12% 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 $14.8 million in Directors’ and Officers’ liability insurance premiums; $10.2 million in lower executive and management compensation costs; $3.5 million in reduced Sarbanes-Oxley 404 compliance costs and external / internal audit fees; and $1.6 million in lower PJM administrative fees resulting from a PUCO order to defer these costs until they can be recovered through rates starting in February 2006. These decreases were partially offset by a $4.1 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. In addition, pension and benefits costs rose by $0.6 million reflecting an increase in pension costs of $2.0 million that was nearly offset by a $1.4 million decrease for other post employment benefits, principally a 2004 adjustment in disability reserves.

Operation and maintenance expense increased $26.7 million or 14% 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 $7.7 million in pension and benefits expenses, $6.4 million higher Sarbanes-Oxley 404 compliance costs and external / internal audit fees, $6.1 million in higher Directors’ and Officers’ liability insurance premiums, and a $2.4 million reduction in capitalized insurance and claims costs. Electric production, transmission and distribution expenses increased $13.1 million, primarily related to planned maintenance during scheduled outages, ash disposal and other maintenance charges. PJM administrative fees of $2.9 million in 2004 for scheduling, system control, and dispatch services also contributed to the increase in expense. These increases were partially offset by a $13.8 million decrease in executive and management compensation.

Depreciation and Amortization

Depreciation and amortization expense was $2.8 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 $5.0 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.

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.

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	43.3		44.8		(1.5		)	45.3		(0.5		)
Other	8.9		7.9		1.0			6.5		1.4
Excise	—		—		-			5.4		(5.4		)
Total	$	105.1	$	103.2	$	1.9		$	106.8	$	(3.6	)

General taxes increased $1.9 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.

Investment Income

Investment income increased by $1.2 million in 2005 compared to 2004 primarily resulting from an increase in interest and dividend income.

Investment income decreased by $21.7 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 a $0.5 million decrease in interest income in 2004 compared to 2003.

Interest Expense

Interest expense decreased $5.4 million or 12% compared to 2004 primarily from $2.6 million of lower debt service charges associated with our early retirement of ESOP debt; lower amortization of $1.1 million associated with reacquired debt; $1.0 million from the elimination of the interest penalty on the $470 million 5.125% Series First Mortgage Bonds resulting from the delayed exchange offer registration of those securities; and $0.2 million of greater capitalized interest in 2005 as compared to 2004.

Interest expense decreased $8.3 million or 16% in 2004 compared to 2003 primarily resulting from the refinancing of debt in 2004 and 2003 for which interest expense was lower by $11.7 million, despite $2.0 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.

Charge for Early Redemption of Debt

In 2005, we recorded $4.1 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 7 of Notes to Consolidated Financial Statements).

Other Income

Other income was $7.6 million greater than 2004 primarily reflecting $3.5 million of additional gains in 2005 over 2004 from sales of pollution control emission allowances; $1.3 million of lower management fees relating to investments; and $4.6 million drop in miscellaneous income deductions; offset by $1.8 million drop in gains from property disposals.

Other income decreased $4.2 million in 2004 compared to 2003 primarily from bank and legal fees associated with DP&L’s revolving credit facilities and non-operating income realized in 2003. In addition, $8.3 million of management fees were offset by an $8.9 million gain on the sale of emission allowances.

Income Tax Expense

Income tax expense for 2005 increased $17.3 million compared to prior year resulting from higher income, increased accrual for open tax years and lower state coal tax 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 include phasing-out the Ohio Franchise Tax, phasing-out the Personal Property Tax for non-utility taxpayers and phasing-in a Commercial Activities Tax. As a result of House Bill 66, income taxes were reduced by $1.6 million. Other applicable provisions of House Bill 66 have been reflected in the consolidated financial statements.

For 2004, income tax expense decreased $29.6 million compared to 2003 primarily reflecting lower pre-tax book income, 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.

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 $46.2 million at December 31, 2005, compared to $17.2 million at December 31, 2004. The increase in cash and cash equivalents of $29.0 million was primarily attributed to $366.8 million from operating activities. These proceeds were used for capital expenditures of $178.4 million and dividends paid to our parent of $150.0 million.

We generated net cash from operating activities of $366.8 million, $381.2 million, and $363.6 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 accounts payable, accounts receivable, and the timing of tax payments. The net cash provided by operating activities in 2004 was primarily the result of operating profitability, and cash

provided from working capital, specifically the timing of tax payments, offset by the rising cost of coal inventories.

Net cash flows provided by investing activities were $178.4 million, $79.9 million, and $65.1 million in 2005, 2004, and 2003, respectively. Net cash flows provided by investing activities for 2005 were primarily due to capital expenditures. 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 provided by investing activities for 2004 were primarily due to capital expenditures, offset by the proceeds from the sale of property. Net cash flows provided by investing activities in 2003 were primarily due to capital expenditures, offset by the settlement of interest rate hedges.

Net cash flows used for financing activities were $159.4 million, $301.3 million, and $298.4 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 $218.9 million of long-term debt and pay common stock dividends to DPL of $150.0 million. These uses of cash were partially offset by the net cash received from the issuance of long-term debt. Net cash flows used for financing activities for 2004 were for the payment of common and preferred dividends and the retirement of long-term debt. Net cash flows used for financing activities in 2003 primarily related to common stock dividends paid to DPL 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 credit facilities (existing or future arrangements), 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 $178 million, $93 million and $98 million in 2005, 2004 and 2003, respectively, and are expected to approximate $360 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 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 $745 million in capital projects, approximately 61% 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, $0.9 million in 2007, $0.7 million in 2008, $0.7 million in 2009 and $0.7 million in 2010. Substantially all of our property is subject to the mortgage lien securing the first mortgage bonds. Debt maturities in 2006 are expected to be financed with 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, we 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 our 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 our 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 us to pay additional interest if (i) our 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, we were 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 us is limited by the provisions of our mortgage; however, management believes that we continue to have sufficient capacity to issue first mortgage bonds to satisfy our requirements in connection with our 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.

In May 2005, we obtained a $100 million unsecured revolving credit agreement that extended and replaced our previous revolving credit agreement of $100 million. The new agreement, renewable annually, expires on May 30, 2010 and provides credit support for our business requirements during this period. This may be increased up to $150 million. The facility contains one financial covenant: total debt to total capitalization ratio is not to exceed 0.65 to 1.00. This covenant is currently met. We 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 our revolving credit agreement.

In August 2005, we 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 August, 2005, we 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 our obligations to the OWDA, OAQDA and Boone County, we entered into a 43^rd Supplemental Indenture to our 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, we renewed our $10 million Master Letter of Credit Agreement with a financial lending institution. This agreement supports performance assurance needs in the ordinary course of business. We have 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, we 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 parent. None of our debt obligations are guaranteed or secured by affiliates and no cross-collateralization exists between any subsidiaries.

Credit Ratings

Currently, our senior secured debt credit ratings are as follows:

	Rating	Outlook	Effective

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

Rate Stabilization Surcharge

On April 4, 2005, we 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, we entered into a settlement agreement that extended our rate stabilization period through December 31, 2010. During this time, we 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:

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	$	682.9	$	—	$	—	$	—	$	682.9
Interest payments	463.9		34.3		68.7		68.7		292.2
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	0.5		0.4		0.1		—		—
Coal contracts (a)	795.1		390.1		273.0		87.0		45.0
Other contractual obligations	505.8		358.3		147.5		—		—

Total contractual obligations	$	2,692.4	$	806.8	$	537.3	$	204.4	$	1,143.9

(a) DP&L-operated units

Long-term debt:

Long-term debt as of December 31, 2005, consists of first mortgage bonds, tax-exempt pollution control bonds and includes an unamortized debt discount. (See Note 7 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:

We have entered into various long-term coal contracts to supply portions of our coal requirements for our 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, we 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.

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

Credit facilities:

In May 2005, we replaced our 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:

We own a 4.9% equity ownership interest in an electric generation company. As of December 31, 2005, we 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.

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 a $16 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 52% and 45%, 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 $25 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 held secured notes with fixed interest rates. At December 31, 2005, we had no short-term borrowings.

The carrying value of our debt was $686.8 million at December 31, 2005, consisting of our first mortgage bonds, our tax-exempt pollution control bonds, and our capital leases. The fair value of this debt was $685.2 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 Date	Amount ($ in millions)		Average Rate
Expected Maturity Date	Amount ($ in millions)		Average Rate

2006	$	0.9	5.3%
2007	0.9		5.3%
2008	0.7		5.8%
2009	0.7		5.8%
2010	0.7		5.8%
Thereafter	682.9		5.0%
Total	$	686.8

Fair Value	$	685.2

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, and 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; 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. Our utility operating companies 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.

DPL files a consolidated U.S. federal income tax return in conjunction with its subsidiaries. The consolidated tax liability is allocated to each subsidiary as specified in the DPL 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 3.2% in 2005 and 3.3% 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 are 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.

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 are maintaining 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 are also maintaining 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

THE DAYTON POWER AND LIGHT COMPANY

Consolidated Statements of Results of Operations

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

Revenues	$	1,276.9		$	1,192.2		$	1,183.4

Operating Expenses
Fuel	317.9			257.0			226.2
Purchased power	147.1			116.4			92.7
Operation and maintenance	198.3			224.4			197.7
Depreciation and amortization	123.9			121.1			116.1
Amortization of regulatory assets, net	2.0			0.7			49.1
General taxes	105.1			103.2			106.8
Total operating expenses	894.3			822.8			788.6

Operating Income	382.6			369.4			394.8

Investment income	2.2			1.0			22.7
Charge for early redemption of debt	(4.1		)	—			—
Other income (deductions)	10.5			2.9			7.1
Interest expense	(38.1		)	(43.5		)	(51.8		)

Income Before Income Taxes and Cumulative Effect of Accounting Change	353.1			329.8			372.8

Income tax expense	138.1			120.8			150.4

Income Before Cumulative Effect of Accounting Change	215.0			209.0			222.4

Cumulative effect of accounting change, net of tax	(3.2		)	—			17.0

Net Income	211.8			209.0			239.4

Preferred dividends	0.9			0.9			0.9

Earnings on Common Stock	$	210.9		$	208.1		$	238.5

See Notes to Consolidated Financial Statements.

THE DAYTON POWER AND LIGHT COMPANY

Consolidated Statements of Cash Flows

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

Operating Activities
Net income	$	211.8		$	209.0		$	239.4
Adjustments:
Depreciation and amortization	123.9			121.1			116.1
Amortization of regulatory assets, net	2.0			0.7			49.1
Deferred income taxes	(13.3		)	(16.2		)	(13.5		)
Income from interest rate hedges	—			—			(21.2		)
Gain on sale of property	—			(1.8		)	—
Cumulative effect of accounting change, net of tax	3.2			—			(17.0		)
Charge for early redemption of debt	4.1			—			—
Changes in working capital:
Accounts receivable	(17.1		)	6.6			(1.0		)
Accounts payable	6.5			11.5			7.3
Net intercompany receivables from parent	(0.1		)	(0.2		)	0.4
Accrued taxes payable	31.5			58.4			(30.6		)
Accrued interest payable	(0.9		)	0.5			(8.8		)
Prepayments	2.3			0.6			(8.2		)
Inventories	(7.9		)	(20.2		)	4.5
Deferred compensation assets	0.7			8.8			50.4
Deferred compensation obligations	6.7			5.2			(46.8		)
Other	13.4			(2.8		)	43.5
Net cash provided by operating activities	366.8			381.2			363.6

Investing Activities
Capital expenditures	(178.4		)	(82.2		)	(116.5		)
Settlement of interest rate hedges	—			—			51.4
Proceeds from sale of property	—			2.3			—
Net cash used for investing activities	(178.4		)	(79.9		)	(65.1		)

Financing Activities
Dividends paid on common stock	(150.0		)	(300.0		)	(298.7		)
Issuance of long-term debt, net of issue costs	210.4			—			465.1
Retirement of long-term debt	(218.9		)	(0.4		)	(463.9		)
Dividends paid on preferred stock	(0.9		)	(0.9		)	(0.9		)
Net cash used for financing activities	(159.4		)	(301.3		)	(298.4		)

Cash and Cash Equivalents:
Net change	29.0			—			0.1
Balance at beginning of year	17.2			17.2			17.1
Balance at end of year	$	46.2		$	17.2		$	17.2

Cash Paid During the Year For:
Interest	$	36.5		$	39.5		$	56.2
Income taxes	$	119.0		$	79.9		$	200.1

See Notes to Consolidated Financial Statements.

THE DAYTON POWER AND LIGHT COMPANY

Consolidated Balance Sheets

	At December 31,
$ in millions	2005			2004

*Assets*

Property:
Property, plant and equipment	$	4,118.0		$	3,944.6
Less: Accumulated depreciation and amortization	(1,973.3		)	(1,864.4		)
Net property	2,144.7			2,080.2

Current Assets:
Cash and cash equivalents	46.2			17.2
Accounts receivable, less provision for uncollectible accounts of $1.0 and $1.1, respectively	182.7			153.8
Inventories, at average cost	77.7			69.8
Prepaid taxes	45.9			46.4
Other current assets	19.3			24.8
Total current assets	371.8			312.0

Other Assets
Regulatory assets	83.8			74.0
Other deferred assets	138.3			175.2
Total other assets	222.1			249.2

Total Assets	$	2,738.6		$	2,641.4

See Notes to Consolidated Financial Statements.

THE DAYTON POWER AND LIGHT COMPANY

Consolidated Balance Sheets

(continued)

	At December 31,
$ in millions	2005		2004

*Capitalization and Liabilities*

Capitalization:
Common shareholder’s equity
Common stock	$	0.4	$	0.4
Other paid-in capital	783.4		782.9
Accumulated other comprehensive income	5.1		43.1
Earnings reinvested in the business	290.5		229.7
Total common shareholder’s equity	1,079.4		1,056.1

Preferred stock	22.9		22.9

Long-term debt	685.9		686.6
Total capitalization	1,788.2		1,765.6

Current Liabilities:
Accounts payable	116.2		107.8
Accrued taxes	167.7		124.8
Accrued interest	9.8		10.7
Other current liabilities	28.4		22.1
Total current liabilities	322.1		265.4

Deferred Credits:
Deferred taxes	323.2		365.8
Unamortized investment tax credit	46.4		49.3
Other deferred credits	258.7		195.3
Total deferred credits	628.3		610.4

ContingenciesNote 11

Total Capitalization and Liabilities	$	2,738.6	$	2,641.4

See Notes to Consolidated Financial Statements.

THE DAYTON POWER AND LIGHT COMPANY

Consolidated Statements of Shareholder‘s Equity

						Accumulated			Earnings
	Common Stock (a)					Other			Reinvested
	Outstanding			Other Paid-In		Comprehensive			In the
$ in millions	Shares	Amount		Capital		Income			Business			Total

2003 Beginning balance	41,172,173	$	0.4	$	780.1	$	(0.8	)	$	381.9		$	1,161.6

2003 :
Net income									239.4
Net change in unrealized gains (losses) on financial instruments, net of reclassification adjustments						17.0
Net change in deferred gains on cash flow hedges						29.5
Minimum pension liability						(0.2		)
Deferred income taxes related to unrealized gains (losses)						(7.3		)
Total comprehensive income												278.4
Common stock dividend									(298.7		)	(298.7		)
Preferred stock dividend									(0.9		)	(0.9		)
Parent company capital contribution
Employee / Director stock plans				0.3								0.3
Other				0.1								0.1

Ending balance	41,172,173	$	0.4	$	780.5	$	38.2		$	321.7		$	1,140.8

2004:
Net income									209.0
Net change in unrealized gains (losses) on financial instruments, net of reclassification adjustments						12.6
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												213.9
Common stock dividend									(300.0		)	(300.0		)
Preferred stock dividend									(0.9		)	(0.9		)
Parent company capital contribution
Employee / Director stock plans				2.3								2.3
Other				0.1					(0.1		)

Ending balance	41,172,173	$	0.4	$	782.9	$	43.1		$	229.7		$	1,056.1

2005:
Net income									211.8
Net change in unrealized gains (losses) on financial instruments, net of reclassification adjustments						1.9
Net change in deferred gains on cash flow hedges						(3.4		)
Minimum pension liability						(63.0		)
Deferred income taxes related to unrealized gains (losses)						26.4
Total comprehensive income												173.7
Common stock dividend									(150.0		)	(150.0		)
Preferred stock dividend									(0.9		)	(0.9		)
Employee / Director stock plans				0.5								0.5
Other						0.1			(0.1		)

Ending balance	41,172,173	$	0.4	$	783.4	$	5.1		$	290.5		$	1,079.4

(a) 50,000,000 shares authorized

See Notes to Consolidated Financial Statements.

THE DAYTON POWER AND LIGHT COMPANY

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies and Overview

Description of Business

The Dayton Power and Light Company is a wholly-owned subsidiary of DPL Inc. (DPL). DP&L is a public utility incorporated in 1911 under the laws of Ohio. We conduct our principal business in one business segment - Electric. 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.

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 DP&L 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.

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 $57.5 million and $53.8 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 3.2% in 2005, 3.3% in 2004 and 3.3% in 2003. Depreciation expense was $123.9 million in 2005, $121.1 million in 2004, and $116.1 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	$	2,509.8	3.0%	$	2,476.8	3.1%
Non-depreciable	15.3		0.0%	15.1		0.0%
Total unregulated	$	2,525.1		$	2,491.9

Total property in service	$	3,952.9	3.2%	$	3,872.6	3.3%
Construction work in process	165.1		0.0%	72.0		0.0%

Total property, plant and equipment	$	4,118.0		$	3,944.6

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.

$ in millions	2004			2003
Reported net income	$	209.0		$	239.4
Earnings effect of adopting FIN No. 47	(0.5		)	(0.4		)
Adjusted net income	$	208.5		$	239.0

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 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.

DPL files a consolidated U. S. federal tax return in conjunction with its subsidiaries, including the Company. The consolidated tax liability is allocated to DPL and its subsidiaries as specified in the

DPL tax allocation agreement which provides a consistent, systematic and rational approach. (See Note 4 of Notes to Consolidated Financial Statements.)

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 $46.2 million at December 31, 2005 and $17.2 million at December 31, 2004.

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.

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 related to DPL Inc. common stock 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 DPL Inc. common stock 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) related to DPL Inc. common stock 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 SFAS 123, these SIUs were valued at the quarter-end market price for DPL’s 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, (SFAS 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.

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. The adoption of EITF 03-13 had no impact on our results of operations, cash flows or 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.

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	57.5			53.8
Partners in commonly-owned plants	37.7			29.5
Refundable franchise tax	11.8			—
Wholesale customers	3.4			4.3
Other	2.2			4.6
Provision for uncollectible accounts	(1.0		)	(1.1		)
Total accounts receivable, net	$	182.7		$	153.8

Inventories, at average cost:
Fuel and emission allowances	$	48.6		$	29.1
Plant materials and supplies	29.1			40.1
Other	—			0.6
Total inventories, at average cost	$	77.7		$	69.8

Other current assets:
Prepayments	$	7.6		$	11.2
Deposits and other advances	5.8			1.6
Current deferred income taxes	4.9			6.8
Other	1.0			5.2
Total other current assets	$	19.3		$	24.8

Other deferred assets:
Master Trust assets	$	107.7		$	106.4
Unamortized loss on reacquired debt	22.0			23.8
Unamortized debt expense	7.4			5.6
Prepaid pension	—			38.2
Other	1.2			1.2
Total other deferred assets	$	138.3		$	175.2

Other current liabilities:
Customer security deposits and other advances	$	19.2		$	17.3
Payroll taxes payable	2.3			0.0
Current portion of Long-term debt	0.9			1.5
Unearned revenues	0.4			0.3
Other	5.6			3.0
Total other current liabilities	$	28.4		$	22.1

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
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	9.3			8.7
Total other deferred credits	$	258.7		$	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 – 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 us 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. We 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 us 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 us to repair damage from the December 2004 and the January 2005 ice storms. We 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 our 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)	$	123.6		$	115.4		$	130.5

Increases (decreases) in tax resulting from-
State income taxes, net of federal effect (b)	7.4			7.0			10.2
Depreciation	(1.3		)	(3.9		)	(2.3		)
Investment tax credit amortized	(2.9		)	(2.9		)	(2.9		)
Non-deductible compensation	0.2			—			13.3
Section 199 – domestic production deduction	(1.6		)	—			—
Accrual for open tax years (c)	11.2			5.3			4.6
Other, net	1.5			(0.1		)	(3.0		)
Total tax expense (d)	$	138.1		$	120.8		$	150.4

Components of Tax Expense
Taxes currently payable (b)	$	149.4		$	136.8		$	163.9
Deferred taxes–
Regulatory assets	—			—			(17.3		)
Depreciation and amortization	(16.4		)	(10.0		)	(10.2		)
Other	8.0			(3.1		)	16.9
Deferred investment tax credit, net	(2.9		)	(2.9		)	(2.9		)
Total tax expense (d)	$	138.1		$	120.8		$	150.4

Components of Deferred Tax Assets and Liabilities

	At December 31,
$ in millions	2005			2004
Net Non-Current Assets (Liabilities)
Depreciation/property basis	$	(367.6	)	$	(381.8	)
Income taxes recoverable	(10.1		)	(11.4		)
Regulatory assets	(9.4		)	(6.5		)
Investment tax credit	16.3			17.3
Compensation and employee benefits	38.7			34.9
Other (e)	8.9			(18.3		)
Net non-current (liabilities)	$	(323.2	)	$	(365.8	)

Net Current Asset
Other	$	4.9		$	6.8
Net Current Asset	$	4.9		$	6.8

(a) The statutory tax rate of 35% was applied to pre-tax income 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 position 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 11 of Notes to Consolidated Financial Statements.)

(d) Excludes $(2.1) million in 2005 and $11.3 million in 2003 of income taxes recorded as cumulative effect of accounting charge, net of income taxes.

(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 zero in 2005 and 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

We sponsor 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, we have 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. We have 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 our 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.

Our 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.

Our 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.

Our 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 our ability to generate that rate of return in the future.

Our 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 our 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:

Benefit Obligation Assumptions	Pension		Postretirement
	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

We expect to contribute $0.4 million to our pension plan and $3.0 million to our other postretirement benefit plan in 2006.

6. Preferred Stock

$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)		Par Value At December 31, 2004 ($ in millions)
Series A	3.75	%	$	102.50	93,280	9.3		9.3
Series B	3.75	%	$	103.00	69,398	7.0		7.0
Series C	3.90	%	$	101.00	65,830	6.6		6.6
Total					228,508	$	22.9	$	22.9

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

As long as any preferred stock is outstanding, our Amended Articles of Incorporation contain provisions restricting the payment of cash dividends on any of our 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 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 were available for Common Stock dividends. We record dividends on our preferred stock as part of interest expense. We expect all 2006 earnings reinvested in the business to be available for common stock dividends, payable to DPL.

7. 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
Guarantee of Air Quality Development
Obligations 6.10% Series due 2030	—			110.0
Obligations for capital leases	3.0			3.8
Unamortized debt discount and premium (net)	(1.5		)	(1.6		)
Total	$	685.9		$	686.6

(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, $0.9 million in 2007, $0.7 million in 2008, $0.7 million in 2009 and $0.7 million in 2010. Substantially all of our property is subject to the mortgage lien securing the first mortgage bonds.

On September 29, 2003, we 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 our 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 our 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 us to pay additional interest if (i) our 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, we were 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 February 2004, we entered into a $20 million Master Letter of Credit Agreement with a financial lending institution. On February 24, 2005, we 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, we entered into a second amendment to extend the term of this agreement for another year. This agreement supports performance assurance needs in the ordinary course of business. We have 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, we had two outstanding letters of credit for a total of $2.2 million.

In May 2005, we 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 our business requirements during this period. This may be increased up to $150 million. The facility contains one financial covenant: total debt to total capitalization ratio is not to exceed 0.65 to 1.00. This covenant is currently met. We 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 our revolving credit agreement.

On August 17, 2005, we 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, we 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 our obligations to the OWDA,

OAQDA and Boone County, we entered into a 43^rd Supplemental Indenture to our First and Refunding Mortgage for a like amount ($214.4 million) of First Mortgage Bonds with The Bank of New York serving as Trustee.

In 2005, we recorded $4.1 million of charges resulting from premiums paid for the early redemption of debt, including write-offs of unamortized debt expense.

8. Stock-Based Compensation

In 2000, DPL’s Board of Directors adopted and its shareholders approved The DPL Inc. Stock Option Plan, which is the basis for our stock-based compensation expense. 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) DPL 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	$	211.8		$	209.0		$	239.4
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	$	213.3		$	206.0		$	236.7

9. 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, we had $119 million of construction in progress at such facilities. Our 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.

Our 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

10. 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
Available-for-sale securities	$	100.4	$	36.7	$	—	$	(3.1	)	$	66.8	$	92.4	$	34.5	$	—	$	(2.9	)	$	60.8
Other	—		—		—		—			—		0.8		0.8		—		—			—

Held-to-maturity debt securities (a)	7.9		—	(0.2	)	—	8.1		14.7		—	(0.1	)	—	14.8

Total assets	$	108.3					$	74.9	$	107.9					$	75.6

Liabilities
Long-term debt (b)	$	685.2					$	686.8	$	681.9					$	688.1

(a) Maturities range from 2006 to 2035.

(b) Includes current maturities.

Realized gains and (losses) for available-for-sale securities were zero and $(0.1) million in 2005, $0.1 million and less than $(0.1) million in 2004, and $1.1 million and $(0.8) million in 2003, respectively.

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.

11. 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, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We have 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. We record 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, we accrue 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. We evaluate 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 August 24, 2004, we, DPL 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, DPL 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, DPL 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, DPL, 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.

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 DPL concerning purported entitlements in connection with the purchase of those investments. We, DPL 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, DPL 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 April 7, 2004, DPL received notice that the staff of the PUCO is conducting an investigation into our financial condition as a result of the issues raised by the Memorandum. On May 27, 2004, the PUCO ordered us to file a plan of utility financial integrity that outlines the actions DPL has taken or

will take to insulate our utility operations and customers from its unregulated activities. We were required to file this plan by March 2, 2005. On February 4, 2005, we filed our protection plan with the PUCO. On June 29, 2005, the PUCO closed its investigation, citing significant positive actions DPL had taken including changes in the Board of Directors as well as our executive management, and that no apparent diminution of service quality had occurred because of the events that initiated the investigation.

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 December 12, 2003, the Office of Federal Contract Compliance Programs (OFCCP) notified us by letter, alleging we 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, we and the OFCCP entered into a Conciliation Agreement whereby we agreed to distribute approximately $0.2 million in compensation to certain affected applicants. We have completed these payments to the affected applicants and supplied to the OFCCP all follow-up reports required under the Conciliation Agreement.

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 our favor, finding we owed no prejudgment interest to the 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	$	682.9	$	—	$	—	$	—	$	682.9
Interest payments	463.9		34.3		68.7		68.7		292.2
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	0.5		0.4		0.1		—		—
Coal contracts (a)	795.1		390.1		273.0		87.0		45.0
Other contractual obligations	505.8		358.3		147.5		—		—
Total contractual obligations	$	2,692.4	$	806.8	$	537.3	$	204.4	$	1,143.9

(a) DP&L-operated units

Long-term debt:

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:

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

Credit facilities:

Guarantees:

12. Certain Relationships and Related Transactions

On March 13, 2000, affiliates of Kohlberg Kravis Roberts & Co. LLC (KKR), purchased a combination of trust preferred securities issued by a trust established by DPL, DPL voting preferred shares and warrants to purchase DPL’s common shares. The trust preferred securities were redeemed at par in 2001. The DPL Series B voting preferred shares had voting power not exceeding 4.9% of the total outstanding voting power of our voting securities. The warrants to purchase approximately 31.6 million DPL common shares (representing approximately 19.9% of the common shares then outstanding) have a term of 12 years and an exercise price of $21 per share. 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 DPL 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. DPL 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. DPL 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 DPL all of the outstanding Series B voting preferred shares. Under the DPL Securityholders and Registration Rights Agreement, 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 DP&L and DPL Boards of Directors for as long as they and their affiliates continue to beneficially own at least 12.64 million of DPL’s common shares, including shares issuable upon exercise of warrants. 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 of DPL. Accordingly, KKR no longer had the right to appoint one member and one observer to both DP&L and DPL Boards of Directors and the DPL Securityholders and Registration Rights Agreement was amended to delete these, and other, rights.

13. 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, DPL received notice that the staff of the PUCO was conducting an investigation into our financial condition 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 us to file a plan of utility financial integrity that outlines the actions DPL has taken or would take to insulate our utility operations and customers from DPL’s unregulated activities. We were required to file this plan by March 2, 2005. On February 4, 2005, we filed our protection plan with the PUCO and expressed our 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 our financial plan of integrity, requesting the PUCO continue the investigation and monitor our progress toward implementation of DPL’s financial plan of integrity. On June 29, 2005, the PUCO closed its investigation, citing significant positive actions taken by us including changes in DPL’s Board of Directors as well as our executive management, and that no apparent diminution of service quality has occurred because of the events that initiated the investigation.

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, we received a notice that the FERC had instituted an operational audit of us 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 and Shareholder of
The Dayton Power and Light Company:

We have audited the accompanying consolidated balance sheets of The Dayton Power and Light Company and subsidiaries (DP&L) as of December 31, 2005 and 2004, and the related consolidated statements 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 schedules are the responsibility of the DP&L’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 DP&L 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 material 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


KPMG
Kansas City, Missouri
February 27, 2006

Report of Independent Registered Public Accounting Firm on Internal Controls

The Board of Directors and Shareholders of
The Dayton Power and Light Company:

We have audited management’s assessment, included in the Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that The Dayton Power and Light Company and subsidiaries (DP&L) 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). DP&L’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 DP&L’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 DP&L 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, DP&L 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 of 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 DP&L 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


KPMG

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,
$ in millions	2005		2004		2005		2004		2005		2004		2005 (a)	2004
Revenues	$	305.1	$	300.4	$	291.4	$	282.8	$	355.5	$	310.2	324.9	$	298.8
Operating Income	91.4		106.9		76.0		89.6		112.1		106.7		103.1	66.2
Income Before Income Taxes and Cumulative Effect of Accounting Change	87.9		99.3		65.1		77.7		100.8		95.3		99.3	57.5
Income Before Cumulative Effect of Accounting Change	53.3		62.0		35.9		47.0		63.1		55.5		62.7	44.5
Net Income	53.3		62.0		35.9		47.0		63.1		55.5		59.5	44.5
Earnings on Common Stock	53.1		61.8		35.7		47.0		62.9		55.5		59.2	43.8
Cash Dividends Paid	75.0		75.0		—		75.0		—		—		75.0	150.0

(a) Earnings in the fourth quarter of 2005 were $15.4 million more than the fourth quarter of 2004 primarily due to higher net margins of $13.7 million (higher revenues of $26.1 million offset by higher fuel and purchased power costs of $12.4 million); lower O&M expense of $19.2 million as a result of lower corporate costs; a $3.7 million reduction of interest expense due largely to lower debt service charges associated with our early retirement of ESOP debt, lower amortization associated with losses on reacquired debt whose amortization periods have expired, and the elimination of the interest penalty on the $470 million 5.125% Series First Mortgage Bonds resulting from the delayed exchange offer registration of those securities; offset by higher taxes of $23.6 million.

F i n a n c i a l a n d S t a t i s t i c a l S u m m a r y (Unaudited)

For the years ended December 31,	2005		2004	2003	2002	2001

Revenues (millions)	$	1,276.9	1,192.2	1,183.4	1,175.8	1,188.2
Earnings on common stock (millions)	$	210.9	208.1	238.5	244.7	232.7

Cash dividends paid (millions)	$	150.0	300.0	298.7	204.5	82.4

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,
Total assets (millions)	$	2,738.6	2,641.4	2,660.1	2,757.3	2,792.1
Long-term debt (millions)	$	685.9	686.6	687.3	665.5	666.6

First mortgage bond ratings–
Fitch Ratings	A-		BBB	A	A	AA
Moody’s Investors Service	Baa1		Baa3	Baa1	A2	A2
Standards & Poor’s Corporation	BB		BB-	BBB-	BBB	BBB+

Number of Preferred Shareholders	329		357	402	426	476

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

None.

Item 9A – Controls and Procedures

Disclosure Controls and Procedures

The Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining the Company’s disclosure controls and procedures. These controls and procedures were designed to ensure that material information relating to the Company and its subsidiaries are communicated to the CEO and CFO. The Company evaluated these disclosure controls and procedures as of the end of the period covered by this report under the supervision of our CEO and CFO. Based on this evaluation, our CEO and CFO concluded that the Company’s disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic reports filed with the Securities and Exchange Commission.

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 principal executive officer and principal financial officer, 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 the Company’s 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)

Directors and Executive Officers

Name	Age	Background and Experience
Robert D. Biggs	63	Director since 2004; Executive Chairman since May 16, 2004. Retired Managing Partner, PricewaterhouseCoopers LLP, Indianapolis, Indiana, since October 1999; Managing Partner, PricewaterhouseCoopers LLP, July 1992 to October 1999.

Paul R. Bishop	62	Director since 2003. Chairman and Chief Executive Officer, H-P Products, Inc., Louisville, Ohio (manufacturer of central vacuum, VACUFLO, and fabricated tubing and fittings for industry) since 2001; President, H-P Products, Inc. from 1996 to 2001. Mr. Bishop is a Director of Hawk Corporation and is a member of Stark Development Board, Mt. Union College Board and Aultman Health Foundation.

Barbara S. Graham	57	Director since 2005; Senior Vice President, Pepco Holdings, Inc. (utility holding company formed with the merger of Pepco and Conectiv) from June 2002 to July 2003; Senior Vice President of Shared Services and CIO, Conectiv (electric and gas utility formed with 1998 merger of Atlantic Energy, Inc. and Delmarva Power and Light Company) from January 1999 to June 2002; Senior Vice President, Conectiv from March 1998 to January 1999. Ms. Graham is a Director of Artisans’ Bank and Chair of the Executive Committee of Swingin’ With a Star (a non-profit organization).

Ernie Green	67	Director since 1991. President and Chief Executive Officer, Ernie Green Industries, Dayton, Ohio (automotive components manufacturer) since 1981. Mr. Green is a Director of Pitney Bowes Inc. and Eaton Corp. Mr. Green is also Chairman of the Central State University Foundation.

Glenn E. Harder	55	Director since 2004. President of GEH Advisory Services, LLC (a firm specializing in strategic advisory services) since October 2002; Executive Leader, Business Services of Baptist State Convention of North Carolina (the largest non-profit organization in North Carolina, involving over 4,000 churches and over one million members) since February 2004; Executive Vice President and Chief Financial Officer of Coventor, Inc. from May 2000 through October 2002; Executive Vice President and Chief Financial Officer of Carolina Power and Light from October 1995 through March 2000. Prior to that, Mr. Harder held a variety of financial positions during his 16 years with Entergy Corporation, including Vice President of Financial Strategies, Vice President of Accounting and Treasurer.

W August Hillenbrand	65	Director since 1992; Vice-Chairman since May 16, 2004. Principal, Hillenbrand Capital Partners and Retired President and Chief Executive Officer, Hillenbrand Industries, Batesville, Indiana (a diversified public holding company that manufactures caskets, hospital furniture, hospital supplies and provides funeral planning services) since 2001; Chief Executive Officer, Hillenbrand Industries from 1989 to 2000. Mr. Hillenbrand is a Director of Hillenbrand Industries and Pella Corporation and is a Trustee of Batesville Girl Scouts and Trustee Emeritus of Denison University.

Lester L. Lyles, General, USAF (Ret.)	59	Director since 2004. Commander of Air Force Materiel Command from April 2000 to August 2003, the 27th Vice Chief of Staff of the United States Air Force from 1999 to 2000. General Lyles is a Trustee of Wright State University, a Director and member of the Audit Committee of General Dynamics Corp. and Director of MTC Technologies. He is also a member of The President’s Commission on U.S. Space Policy.

James V. Mahoney	60	Director since 2004. President and Chief Executive Officer of DPL Inc. and DP&L since May 16, 2004; President, DPL Energy LLC, a wholly-owned subsidiary responsible for wholesale and retail energy sales and marketing from January 2003 to September 2004; President, Energy Market Solutions, an energy consulting firm from August 2002 to January 2003; President and Chief Executive Officer, EarthFirst Technologies, Incorporated, a company that licenses evolving technologies for environmental and alternate energy solutions from August 2001 to August 2002; Senior Vice President, PG&E National Energy Group, a wholesale power supplier from May 1999 to July 2001; Senior Vice President, U.S. Generating Company from March 1998 to May 1999. Mr. Mahoney serves on the boards of Rebuilding Together Dayton, Culture Works, Dayton Development Coalition and the Dayton Business Committee. Mr. Mahoney joined us in 2003.

Ned J. Sifferlen, Ph. D.	64	Director since 2004; President Emeritus, Sinclair Community College from September 2003 to present; President, Sinclair Community College from September 1997 to August 2003. Dr. Sifferlen is Chairman of the Board of Trustees of Good Samaritan Hospital and Samaritan Health Partners and is a Director on the Board for both Premier Health Partners and Think TV Public Television.

Executive Officers who are not Directors

Name	Age	Position, Principal Occupation, Business Experience and Directorships
Miggie E. Cramblit	50	Vice President, General Counsel and Corporate Secretary, DPL Inc. and DP&L since January 2005; Vice President and General Counsel, DPL Inc. and DP&L from June 2003 to December 2004; Counsel and Corporate Secretary, Greater Minnesota Synergy from October 2001 to June 2003; Chief Operating Officer, Family Financial Strategies from June 1999 to May 2001; Vice President and General Counsel, Reliant Energy/Minnegasco from December 1990 to May 1999. Ms. Cramblit is on the Executive Advisory Board of a Special Wish Foundation, a virtual mentor with Menttium Corporation, and a board member of the Foodbank, the Dayton Philharmonic Orchestra and the Miami Valley Child Development Centers. Ms. Cramblit joined us in 2003.

John J. Gillen	52	Senior Vice President and Chief Financial Officer, DPL Inc. and DP&L since December 2004; Consultant, October 2003 to November 2004; Partner, PricewaterhouseCoopers LLP, from October 1990 to September 2003. Mr. Gillen is a member of the American Institute of Certified Public Accountants. He is also a member of the President’s Council of the Magee Rehabilitation Centre. Mr. Gillen joined us in 2004.

Arthur G. Meyer	56	Vice President, Corporate and Regulatory Affairs, DPL Inc. and DP&L from January 2005; Vice President and Corporate Secretary, DPL Inc. and DP&L from August 2002 to December 2004; Vice President, Legal and Corporate Affairs, DP&L from November 1997 to August 2002. Mr. Meyer is Chair of the Greater Dayton Public Television Board of Trustees and is a member of the Wilberforce University Board of Trustees. He also serves on the Ohio Electric Utility Institute Board of Directors, the Miami Valley Regional Planning Commission Board of Directors, and the Capitol Square Foundation Board of Directors. Mr. Meyer joined us in 1992.

Gary Stephenson	41	Vice President-Commercial Operations, DPL Inc. and DP&L since September 2004; Vice President, Commercial Operations, InterGen from April 2002 to September 2004; Vice President, Portfolio Management, PG&E National Energy Group (successor to PG&E Energy Trading) from January 2000 to April 2002; Director, Portfolio Management, PG&E Energy Trading from January 1998 to December 1999. Mr. Stephenson joined us in 2004.

Patricia K. Swanke	47	Vice President, Operations, DP&L since September 1999 (responsible for electric transmission and distribution operations); Managing Director, DP&L from September 1996 to September 1999. Ms. Swanke serves on the Board of Trustees of the Dayton Arts Center Foundation, the Greene County Community Foundation, the K12 Gallery for Youth, and the Mayor’s Commission on Adult Literacy. Ms. Swanke joined us in 1990.

W. Steven Wolff	52	President, Power Production, DPL Inc. and DP&L since 2003; Vice President, Power Production, DPL Inc. and DP&L from August 2002 to January 2003; Director, Power Production, DP&L from January 2002 to August 2002; Manager, O.H. Hutchings Station, DP&L from August 2001 to January 2002; Captain, U.S. Navy from November 1996 to August 2001. Mr. Wolff is a member of the Victoria Theater Board of Directors, the Executive Boards of the Miami Valley Council of the Boy Scouts of America and the Cox Arboretum Board of Trustees. Mr. Wolff joined us in 2001.

Director and Management Changes

Mrs. Jane G. Haley, Chairman, President and Chief Executive Officer, Gosiger Inc., and a director since 1978, did not stand for re-election in 2005.

On April 26, 2005, Ms. Barbara S. Graham was elected to the Board of Directors for both DPL Inc. and the Company.

On August 29, 2005, we and DPL appointed Joseph R. Boni III as Treasurer.

On September 15, 2005, James F. Dicke, II, resigned from the Board of Directors for both DPL Inc. and the Company.

Audit Committee

DPL has a separately-designated standing audit committee (the Audit Committee) that oversees our auditing, accounting, financial reporting and internal control functions, appoints our independent public accounting firm and approves its services. One of its functions is to assure that the independent public accountants have the freedom, cooperation and opportunity necessary to accomplish their functions. The Audit Committee also assures that appropriate action is taken on the recommendations of the independent public accountants. DPL’s revised Charter of the Audit Committee, which describes all of the Audit Committee’s responsibilities, is posted on DPL’s website at www.dplinc.com.

The Audit Committee currently consists of the following independent directors: W August Hillenbrand, Chair, Glen E. Harder, Vice Chair, Ernie Green and Ned Sifferlen. The Board of Directors has determined that each member of the Audit Committee meets the independence requirements contained in the New York Stock Exchange (NYSE) Corporate Governance Rules and Rule 10A-3(b)(1) of the Exchange Act and is financially literate as defined by the NYSE. In addition, Mr. Harder qualifies as an “audit committee financial expert” within the meaning of SEC regulations.

Code of Business Conduct and Ethics

All of our directors, officers and employees must act ethically at all times and in accordance with DPL’s Code of Business Conduct and Ethics. This code satisfies the definition of “code of ethics” pursuant to the rules and regulations of the SEC and complies with the requirements of the NYSE.

Any changes or waivers to the Code of Business Conduct and Ethics for our officers or directors may only be made by the Board or a committee thereof and must be disclosed promptly to shareholders.

DPL’s Corporate Governance Guidelines, Code of Business Conduct and Ethics, and the charters of the Audit Committee, Compensation Committee and the Nominating and Corporate Governance Committee are posted on DPL’s website at www.dplinc.com.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors and executive officers to file reports of ownership and changes of ownership of DPL common shares and common share units with the SEC. We believe that during fiscal 2005 all filing requirements applicable to its directors and executive officers were timely met.

Shareholder Communications

Shareholders and other interested persons may contact the non-management directors individually or as a group by writing to such director(s) at The Dayton Power and Light Company, c/o Corporate Secretary, 1065 Woodman Drive, Dayton, Ohio 45432. Shareholders may also send communications within the meaning of Item 7(h) of Schedule 14A under the Exchange Act to one or more members of the Board by writing to such director(s) or to the whole Board at The Dayton Power and Light Company, c/o Corporate Secretary, 1065 Woodman Drive, Dayton, Ohio 45432.

Item 11 - Executive Compensation

Summary Compensation Table

Set forth below is certain information concerning the compensation of the Chief Executive Officer and each of our four most highly compensated executive officers for the last three fiscal years, for services rendered in all capacities.

		Annual Compensation				Long-Term Compensation
Name and Principal Position	Year	Salary ($)	Bonus ($)		Other Annual Compensation (1) ($)	Securities underlying Options (#)	LTIP (2) ($)		All Other Compensation (3) ($)
James V. Mahoney	2005	515,000	650,000		49,109	—	586,000	(5)	—
President and Chief	2004	471,000	269,000		35,992	20,000	398,000	(4)	—
Executive Officer DPL Inc. and DP&L	2003	425,000	150,000		5,179	100,000	184,000		259,653

Robert D. Biggs	2005	500,000	1,500,000	(7)	259,077	350,000	—		101,560
Executive Chairman	2004	149,000	500,000		65,759	200,000	—		1,936,925
DPL Inc. and DP&L	2003	—	—		—	—	—		—

John J. Gillen	2005	319,000	300,000		95,791	—	85,300	(6)	50,934
Senior Vice President	2004	—	—		—	30,000	—		—
Chief Financial Officer DPL Inc. and DP&L	2003	—	—		—	—	—		—

Patricia K. Swanke	2005	258,000	250,000		2,503	—	205,000		119,998
Vice President,	2004	249,000	143,000		4,539	—	270,000	(4)	67,692
Operations DP&L	2003	230,000	80,000		1,061	—	193,000		35,797

W. Steven Wolff President,	2005	271,000	200,000		85,884	—	205,000		—
DPL Power Production	2004	263,000	119,000		33,562	—	234,000	(4)	—
DPL Inc. and DP&L	2003	250,000	113,000		14,905	—	279,000		—

(1) See details of “Other Annual Compensation” in the following table.

(2) Amounts in this column represent annualized incentives earned based on achievement of predetermined total return to shareholder measures and under a long-term incentive program. In 2005, 2004 and 2003, total return to shareholders met the criteria, and incentive amounts were earned.

(3) See details of “All Other Compensation” in the table on the following page.

(4) Includes interest on the 2004 LTIP awards as follows: Mr. Mahoney - $4,000; Ms. Swanke - $10,000; and Mr. Wolff - $14,000.

(5) Mr. Mahoney’s LTIP award for 2005 was $576,000 of which one third ($192,000) was payable immediately upon grant and the remaining two-third will vest equally at the end of 2006 and 2007.

(6) Mr. Gillen’s LTIP award for 2005 was $256,000 of which one third ($86,300) was payable immediatedly upon grant and the remaining two-thirds will vest equally at the end of 2006 and 2007.

(7) Includes $500,000 paid in recognition of Mr. Biggs’ significant efforts in leading the effort to sell DPL’s financial asset portfolio.

DPL Inc. Other Annual Compensation Detail
Officer/ Director	Year	Personal Use of Plane (No Gross-Up) ($)	Commuting Plane Use (Gross-Up) ($)	Medical Expenses (Gross-Up) ($)	Corporate Car Usage (Gross-Up) ($)	Group Term Life Insurance ($)	Financial Planning (Gross-Up) ($)	ESOP/ 401(k) ($)	TOTAL

Mahoney	2005	32,859	—	7,726	—	7,524	—	1,000	49,109
	2004	8,338	—	21,751	—	4,903	—	1,000	35,992
	2003	—	—	—	—	4,179	—	1,000	5,179

Biggs	2005	58,738	191,402	—	4,535	4,402	—	—	259,077
	2004	18,751	42,038	—	3,201	1,769	—	—	65,759
	2003	—	—	—	—	—	—	—	—

Gillen	2005	—	81,017	—	11,342	2,432	—	1,000	95,791
	2004	—	—	—	—	—	—	—	—
	2003	—	—	—	—	—	—	—	—

Swanke	2005	—	—	1,413	—	90	—	1,000	2,503
	2004	—	—	3,449	—	90	—	1,000	4,539
	2003	—	—	—	—	61	—	1,000	1,061

Wolff	2005	790	—	65,963	—	138	17,993	1,000	85,884
	2004	3,041	—	22,249	—	133	7,139	1,000	33,562
	2003	6,659	—	—	—	141	7,105	1,000	14,905

DPL Inc. All Other Compensation Detail

Officer/ Director	Year	Annuity ($)		Annuity Gross-Up Amount ($)	Board Fees ($)	Temporary Living & Relocation (Gross-Up) ($)	Legal Services ($)	SIUs ($)	TOTAL ($)

Mahoney	2005	—		—	—	—	—	—	—
	2004	—		—	—	—	—	—	—
	2003	—		—	—	259,653	—	—	259,653

Biggs	2005	—		—	—	52,431	49,129	—	101,560
	2004	897,345	(1)	671,166	348,000	20,414	—	—	1,936,925
	2003	—		—	—	—	—	—	—

Gillen	2005	—		—	—	50,934	—	—	50,934
	2004	—		—	—	—	—	—	—
	2003	—		—	—	—	—	—	—

Swanke	2005	—		—	—	—	—	119,998	119,998
	2004	—		—	—	—	—	67,692	67,692
	2003	—		—	—	—	—	35,797	35,797

Wolff	2005	—		—	—	—	—	—	—
	2004	—		—	—	—	—	—	—
	2003	—		—	—	—	—	—	—

(1) See the description of Mr. Biggs’ employment agreement in the section of this Form 10-K entitled “Employment Agreements” for a description of the annunity.

Option Grants in Last Fiscal Year

The following table sets forth information concerning individual grants of stock options made to the named executive officer(s) during the fiscal year ended December 31, 2005.

	Individual Grants
Name	Number of Securities Underlying Options Granted (#)		% of Total Options Granted to Employees in Fiscal Year	Exercise Price ($/Sh)		Expiration Date		Grant Date Present Value (1) ($)
Robert D. Biggs	350,000 (2	)	100%	$	26.82		08/31/08		$	1,330,000

(1) The grant date present value was determined using the Black-Scholes pricing model. Significant assumptions used in the model were: expected volatility 26%, risk-free rate of return 3.8%, dividend yield of 3.7% and time of exercise 3 years.

(2) Options granted pursuant to our Stock Option Plan on August 31, 2005. These options vest and become exercisable on June 30, 2006.

Aggregated Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values

The following table sets forth information concerning exercise of stock options during fiscal year 2005 by each of the named executive officers and the fiscal year-end value of unexercised options.

Name	Shares acquired on exercise (#)	Value realized ($)	Number of securities underlying unexercised options at fiscal year end (#)		Value of unexercised in-the- money options at fiscal year end (1) (#)
			Exercisable	Unexercisable	Exercisable	Unexercisable
James V. Mahoney	—	—	80,000	40,000	630,000	405,200
Robert D. Biggs	—	—	100,000	450,000	507,000	225,000
John J. Gillen	—	—	10,000	20,000	10,100	20,200
Patricia K. Swanke	—	—	50,000	—	—	—

(1) Unexercised options were in-the-money if the fair market value of the underlying shares exceeded the exercise price of the option at December 31, 2005.

Pension Plans

The following table sets forth the estimated total annual benefits payable under the DP&L retirement income plan and the Supplemental Executive Retirement Plan (SERP), if applicable, to executive officers at normal retirement date (age 65) based upon years of credited service and final average annual compensation (including base and incentive compensation) for the three highest years during the last five years:

Final Average

Annual Earnings ($)

Total Annual Retirement Benefits for
Years of Credited Service at Age 65 ($)

10 Years

15 Years

20 Years

30 Years

210,000

49,398

74,097

98,796

132,417

The years of credited service are: Mr. Mahoney – 2 years; Mr. Biggs – (not applicable due to employment agreement); Mr. Gillen – 0 years; Ms. Swanke – 14 years; and Mr. Wolff – 3 years. Benefits are computed on a straight-life annuity basis, are subject to deduction for Social Security benefits and may be reduced by benefits payable under retirement plans of other employers.

Deferred Compensation Distributions

We maintain a Key Employee Deferred Compensation Plan (the DCP) and a 1991 Amended Directors’ Deferred Compensation Plan (the Directors’ DCP and collectively with the DCP, the Deferred Compensation Plans) for certain officers, directors and other key employees. The Deferred Compensation Plans generally enable participants to defer all or a portion of their cash compensation earned in a particular year. If an individual elects to defer any amount, such deferred amounts are reported as compensation in the year earned and are credited to the individual’s deferred compensation plan account. We have provided for our obligations to participants through a trust, which is included in the Consolidated Balance Sheet in “Other Assets — Other.” Deferred compensation plan account balances accrue earnings based on the investment options selected by the participant. Interest, dividends and market value changes

are reflected in the individual’s deferred compensation plan account. Deferred compensation plan account balances generally are paid following the termination of the participant’s employment with us, in a lump sum or over time as determined by the participant’s deferral election form, and in-service distributions generally are not allowed. In certain circumstances the plan provides for a 10% penalty for early withdrawal. Payments under the DCP are in cash or our common shares, provided that distributions attributable to investments in our common shares must be paid in common shares. Certain purported amendments to the Deferred Compensation Plans purportedly made in December 2003 had the effect of eliminating some of these restrictions for certain former senior executives and facilitating these former executive officers to receive cash distributions from their deferred compensation balances. We have initiated legal proceedings challenging the validity of these purported amendments and the distributions. (See “Certain Legal Proceedings.”)

We have also maintained a Management Stock Incentive Plan (the MSIP and together with the Deferred Compensation Plans, the Plans) for key employees selected by the Compensation Committee. New awards under the MSIP were discontinued in 2000. Under the MSIP, the Compensation Committee granted Stock Incentive Units (SIUs) to MSIP participants, with each SIU representing one DPL common share. SIUs were earned based on the achievement of performance criteria set by the Compensation Committee and vested over time (subject to acceleration of earning and vesting on the occurrence of certain events or at the discretion of our Chief Executive Officer or the Compensation Committee). Earned SIUs were credited to a participant’s account under the MSIP and accrue dividends like our common shares. Under the MSIP, earned and vested SIUs were to be paid in our common shares in a lump sum or over time as determined by the participant’s deferral election.

We have initiated legal proceedings which challenge the validity of purported amendments to the MSIP and DCP. (See “Certain Legal Proceedings.”) Notwithstanding this challenge to the validity of the purported amendments to the Plans, we have accounted for the Plans as they have been administered.

We maintain a Supplemental Executive Retirement Plan (SERP). In February 2000, the Compensation Committee approved certain modifications to the SERP.

Employment Agreements

On February 23, 2006, our and DPL’s Board of Directors approved a comprehensive modification to our executive compensation and benefits program. The new program covers the following nine officers of the Company and/or DPL: President and CEO; Senior Vice President and CFO; President, Power Production; Vice President, Operations; Vice President-Commercial Operations; Vice President, General Counsel and Corporate Secretary; Vice President; Treasurer; and Corporate Controller. As of March 6, 2006, the following officers have signed their Participation Agreement and Waiver: President and CEO; President, Power Production; Vice President, Operations; Vice President - Commercial Operations; Vice President, General Counsel and Secretary; Vice President; Treasurer; and Corporate Controller.

As a result of the passage of the new program, each eligible officer, except for Mr. Biggs, who has signed a Participation Agreement and Waiver, will be compensated under the executive compensation and benefits program. Under the Participation Agreement and Waiver, the officer voluntarily waives and releases all rights he or she had under his or her employment agreement and certain other compensatory plans. In addition to participation under the executive compensation and benefits program, each eligible officer is permitted to retain certain benefits uniquely awarded to such officer under the former employment agreements and compensation plans. Mr. Biggs’ employment agreement is summarized below. In addition, the employment agreements for each of the other named executive officers are summarized below. The employment agreement of Mr. Gillen will remain effective until a Participation Agreement and Waiver is signed.

Robert D. Biggs

Mr. Biggs has served as the Chairman of the Board of Directors of DPL and DP&L since May 16, 2004, and he was appointed Executive Chairman of DPL and DP&L pursuant to an employment agreement, dated July 21, 2004, and effective as of May 16, 2004. We and DPL signed an amended and restated employment agreement with Mr. Biggs on August 31, 2005. The term of Mr. Biggs’ amended and restated employment agreement is through June 30, 2006, unless terminated, with or without cause, by us, DPL or Mr. Biggs upon 90 days written notice; provided that we or DPL may terminate Mr. Biggs for cause without prior notice. The agreement also automatically terminates upon Mr. Biggs’ death or disability. Mr. Biggs’ agreement includes non-compete and confidentiality provisions.

Compensation and Indemnification

Mr. Biggs’ agreement provides for (i) an annual base salary of $500,000; (ii) his eligibility to receive an annual bonus under the Management Incentive Compensation Plan (MICP) with a guaranteed minimum of at least $500,000; (iii) stock options to purchase 350,000 shares of Company common stock at an exercise price to be determined pursuant to our Stock Option Plan and that will vest and become exercisable on June 30, 2006; and (iv) term life insurance policy with a death benefit of $1,000,000. (We have satisfied this insurance obligation by purchasing a policy with a death benefit of $500,000 and self-insuring the balance.) In addition, we will provide Mr. Biggs with the use of corporate aircraft in connection with his travel between Dayton and his home in Florida and will pay a tax gross-up in respect of such use. Previously in October 2004, pursuant to his initial employment agreement, we awarded Mr. Biggs 200,000 options to purchase our common shares at an exercise price determined under the Stock Option Plan with half of the options vesting on May 16, 2005, and the balance vesting on May 16, 2006.

Further, Mr. Biggs retired as a Managing Partner of PricewaterhouseCoopers LLP (PwC) in 1999 and received retirement benefits from PwC which, if continued, could have affected whether PwC qualified as our independent auditing firm. PwC was our and DPL’s independent auditor until March 2003 and was required to give its consent to the filing of our 2003 Form 10-K. In order for PwC to continue to qualify as an independent auditor, Mr. Biggs agreed to accept his retirement benefit from PwC in the form of an annuity which provides an annual retirement benefit that is $71,000 less than the amount he previously received from PwC directly. To compensate Mr. Biggs for the resulting reduction in his PwC retirement benefits, we and DPL purchased an annuity that pays Mr. Biggs $71,000 per year for life in addition to the compensation described above. We and DPL will also provide Mr. Biggs with gross-up payments for any income taxes incurred by him in connection with the annuity such that Mr. Biggs is in the same after-tax position as if no income taxes had been imposed. Upon Mr. Biggs’ death, Mr. Biggs’ spouse will receive an annual amount equal to 30% of the total annuity payable to Mr. Biggs for life. This arrangement will continue to be binding even if Mr. Biggs no longer serves as Executive Chairman.

Mr. Biggs’ agreement states that we and DPL will indemnify him against any and all losses, liabilities, damages, expenses (including attorney’s fees), judgments and amounts paid in settlement incurred by Mr. Biggs in connection with any claim, action, suit or proceeding (whether civil, criminal, administrative or investigative), including any action by or in the right of either us or DPL, by reason of any act or omission to act in connection with the performance of his duties under the agreement to the full extent that we and DPL are permitted to indemnify a director, officer, employee or agent against the foregoing under the respective Codes of Regulations of DPL and DP&L and Ohio law, including without limitation, Section 1701.13(E) of the Ohio Revised Code.

Termination

If Mr. Biggs’ employment is terminated for any reason, Mr. Biggs’ agreement provides for (i) his annual base salary through the date of his termination and (ii) any accrued benefits under our and DPL’s compensation or benefit plans or arrangements in accordance with their terms, including any unpaid bonuses payable in respect of a completed fiscal year.

If Mr. Biggs’ employment is terminated without cause prior to a change of control, in addition to the payments and benefits described above, Mr. Biggs’ agreement provides for (i) a lump sum cash payment equal to his annual base salary; (ii) any MICP amounts earned or otherwise payable as calculated under the agreement; (iii) continued benefits for up to one year after employment is terminated; and (iv) the vesting of all awarded stock options; provided that Mr. Biggs executes and delivers a release pursuant to which he fully and unconditionally releases any claims that he may have against us or DPL.

Change of Control

If on June 30, 2006, we are in discussions with a potential acquirer relating to a transaction which could result in a change of control, Mr. Biggs can extend his employment contract for six-month successive periods. If a change of control occurs while Mr. Biggs is employed by us, besides the amount he is to receive as set forth in the first paragraph above under “Termination,” Mr. Biggs’ agreement provides for (i) a lump sum cash payment equal to the sum of (a) 200% of the annual base salary plus an average of the sum of (a) $500,000 and (b) the award payment made to Mr. Biggs under the MICP for the three years preceding the date of termination or for the number of years he has participated in the MICP, if less than three, including any deferrals; (ii) any MICP amounts earned or otherwise payable as calculated under the agreement; (iii) a gross-up payment if any excise tax is imposed upon a change of control such that Mr. Biggs is in the same after-tax position as if no excise tax was imposed; (iv) the continuation of his benefits for up to three years following his termination; and (v) the vesting of all of his awarded stock options; provided that Mr. Biggs executes and delivers a release pursuant to which he fully and unconditionally releases any claims that he may have against us or DPL. If payments to Mr. Biggs are made under the first subparagraph above due to a change in control, Mr. Biggs shall also receive one-half of the amount calculated under the first subparagraph above in consideration of his compliance with certain non-compete and confidentiality provisions of his agreement.

The passage of our comprehensive executive compensation and benefits program on February 23, 2006, does not impact Mr. Biggs’ amended and restated employment agreement or management stock option agreements.

James V. Mahoney

Mr. Mahoney served as the President and Chief Executive Officer of the Company and DPL from May 16, 2004, pursuant to an employment agreement dated December 14, 2004. Prior to this promotion, Mr. Mahoney served as President of DPL Energy, LLC from January 2003 until May 16, 2004. The term of Mr. Mahoney’s employment agreement was indefinite until terminated by us or Mr. Mahoney, with or without cause, upon 90 days’ written notice, provided that we can terminate the agreement with cause without prior notice. The agreement also automatically terminates upon Mr. Mahoney’s death or disability.

Compensation

Mr. Mahoney’s agreement provided for (i) an annual base salary of not less than $500,000; (ii) participation in the MICP, in which during 2005, he had the opportunity to earn $250,000 at 100% of the target performance; (iii) participation in the our Long Term Incentive Plan (LTIP), in which during 2005, he had the opportunity to earn $450,000 at 100% of target performance; (iv) stock options to purchase up to 20,000 shares of common stock; and (v) such fringe benefits (including medical, life and disability insurance benefits and qualified retirement benefits) as were generally made available to other executive level employees. Awards earned pursuant to the LTIP would vest in three equal installments on December 31 of each year, commencing with the year in which an award was granted.

Termination

If Mr. Mahoney’s employment was terminated (i) for cause as defined in the employment agreement, or (ii) due to his death or disability, or (iii) for any reason at any time, Mr. Mahoney’s employment agreement provides for (a) a lump sum cash payment to Mr. Mahoney equal to the sum of his unpaid base salary through the date of termination; (b) the amount of any awards, with respect to any completed period which, pursuant to the MICP or LTIP, had been earned but not yet paid; and (c) payment of any other accrued benefits to which Mr. Mahoney is entitled through the date of termination. If Mr. Mahoney terminated his employment for any reason at any time, we agreed to pay an additional amount equal to his annual base salary.

If we or DPL terminated Mr. Mahoney’s employment without cause and a change of control had not occurred or was not pending, Mr. Mahoney’s employment agreement provided for (i) the benefits described in the paragraph above; (ii) the amount of any awards, with respect to any completed period which, pursuant to the MICP and LTIP, had been earned but were not vested through the date of termination; and (iii) continued coverage under the health benefit plan for executive employees at the same cost and terms as in effect immediately prior to the date of notice of (a) the first anniversary of his termination date or (b) the date an essentially equivalent benefit is made available to Mr. Mahoney at substantially similar cost, provided that in order to secure these payments, Mr. Mahoney executed and delivered a release pursuant to which he fully and unconditionally released any claims that he may have had against us and our affiliates.

Change of Control

If we terminated Mr. Mahoney’s employment within 12 months of a change of control and (i) such termination is without cause or (ii) Mr. Mahoney resigned for “Good Reason” as defined in the employment agreement (“Good Reason” is defined as (i) assignment of duties without his express consent inconsistent with the written objectives of his position, a change in his reporting responsibilities, his removal from or any failure to re-elect Mr. Mahoney to his position or office; (ii) failure to have his annual base salary raised when salary adjustments are historically made; (iii) a reduction in his base salary; (iv) failure by us or DPL to continue a benefit plan, including incentive plans; (v) the relocation of our principal executive offices outside of Montgomery County, Ohio, if at the time of a change of control, Mr. Mahoney is based at the principal offices; (vi) being required to base more than fifty miles from the location he was based at the time of the change of control or the failure to reimburse for moving expenses, if Mr. Mahoney consents to moving his base and permanent residence; (vii) excessive travel that necessitates overnight absences; (viii) the failure by us or DPL to obtain the assumption of his agreement by any successor; (ix) termination without cause or without being provided with a notice of termination; or (x) we terminate Mr. Mahoney’s employment without cause or without notice of termination), Mr. Mahoney’s employment agreement provided for (a) the benefits listed in the first paragraph under “Termination” above; (b) a lump sum cash payment equal to 200% of the sum of (A) Mr. Mahoney’s annual base salary (before deduction of employee deferrals) at the highest of (aa) the rate in effect on the date of termination or (bb) the rate in effect at the time of the change in control; plus (B) the average of the last three (or the number of years he has participated if less than three) annual award payments made to him prior to the date of termination pursuant to the MICP or LTIP, including any portion deferred to his deferred compensation plan account; (c) the amount of any MICP or LTIP award earned with respect to a completed period but unvested as of termination, or if the termination preceded the actual determination of such incentive compensation (under the MICP or LTIP) or the completion of a period in which he could have earned such incentive compensation, an amount equal to the average of the award payments made to him under the MICP or LTIP (as applicable) for the three years preceding the date of termination (or for the number of years he had participated in such plan if less than three), including any portion deferred to his deferred compensation plan account; (d) continuation of all life, medical, accident and disability insurance for Mr. Mahoney and his eligible dependents until the third anniversary of the date of termination or the date an essentially equivalent benefit was made available to Mr. Mahoney by a subsequent employer; thereafter, Mr. Mahoney would have had the right to have assigned to him at no cost any such insurance coverage on Mr. Mahoney owned by us; and (e) a gross-up payment equal to any net amounts paid by Mr. Mahoney for any excise tax owed under Section 4999 of the Internal Revenue Code of 1986 for payments made to Mr. Mahoney under this employment agreement, such that Mr. Mahoney was in the same after-tax position as if no excise tax was imposed.

Upon a change of control, Mr. Mahoney’s employment agreement stated that we would transfer cash or other property in an amount sufficient to fund all change of control benefits and payments to the Amended and Restated Master Trust.

John J. Gillen

Mr. Gillen serves as one of our executive officers since December 21, 2004 pursuant to an employment agreement dated as of December 21, 2004. The term of Mr. Gillen’s employment agreement is annually renewable but otherwise indefinite until terminated by either Mr. Gillen or us, with or without cause, upon 90 days’ notice; provided that we may terminate the agreement with cause without prior notice. The agreement also terminates automatically upon Mr. Gillen’s death or disability. If Mr. Gillen executes a Participation Agreement and Waiver, whereby he agrees to participate in the new executive compensation and benefits program previously described, then his employment agreement terminates.

Compensation

Mr. Gillen’s agreement provides for (i) an annual base salary of not less than $320,000; (ii) participation in such short-term and long-term bonus, incentive compensation, deferred compensation and similar plans as we or the Compensation Committee determine; and (iii) such fringe benefits as are generally made available to all other employees, the Executive Medical Plan, the annual physical program and financial planning services in effect from time to time. In addition, Mr. Gillen was granted stock options allowing Mr. Gillen the opportunity to purchase up to 30,000 shares of Company common stock. Such stock options vest ratably over the first three anniversaries of the effective date of his employment agreement.

Termination

If Mr. Gillen’s employment is terminated without “cause,” then the agreement provides for (i) the payment of his unpaid base salary earned through the date of termination; (ii) any MICP or LTIP with respect to any completed periods or otherwise earned by Mr. Gillen; (iii) any and all accrued benefits in which Mr. Gillen is entitled; (iv) an amount equal to the sum of one years’ base salary and the amount of Mr. Gillen’s target MICP bonus for the year of termination; and (v) continued executive healthcare coverage until either the sooner of one year from the date of termination or the date Mr. Gillen receives a substantially similar health care package at substantially the same cost, provided that Mr. Gillen executes and delivers a release pursuant to which he fully and unconditionally releases any claims he has against us and our affiliates.

“Cause” for purposes of Mr. Gillen’s employment agreement is defined as (i) commission of a felony; (ii) embezzlement; (iii) the illegal use of drugs; or (iv) in the absence of a change-in-control, the failure by Mr. Gillen to substantially perform his duties hereunder (other than any such failure that resulted from his physical or mental illness or other physical or mental incapacity) as reasonably determined by us. If Mr. Gillen’s employment is terminated for “cause,” he is to receive the compensation listed in subparagraphs (i) to (iii), inclusive as listed in the immediately preceding paragraph.

Change of Control

If Mr. Gillen’s employment is terminated within 36 months of a change of control, Mr. Gillen’s agreement provides for (i) his receipt of the compensation listed in subparagraphs (i) to (iii), inclusive as listed in the second preceding paragraph; (ii) an amount equal to 200% of the sum of his annual base salary, before deduction of any deferred amounts, and the average of the award payments made under the MICP for the three years preceding the date of termination or for the number of years he had participated in the plan if less than three years, including any portion deferred to his deferred compensation plan account; (iii) the amount of any MICP award earned in respect to a completed period but unvested as of the date of termination or the amount of a MICP award that could have been earned but was not due to the date of termination preceding the determination of the MICP, in which case Mr. Gillen is to receive an award equal to the average of his MICP award over the past three years preceding the date of termination; (iv) continuation of all life, medical, accident and disability insurance for Mr. Gillen and his eligible dependents until the third anniversary of the date of termination or the date an essentially equivalent benefit is made available to Mr. Gillen by a subsequent employer; and (v) gross-up payments for excise taxes.

If Mr. Gillen’s employment is terminated within 36 months of a change in control due to his disability, his employment agreement provides for benefits under our and DPL’s salary continuation plan or disability insurance in addition to the specific benefits set forth in the immediately preceding paragraph.

Patricia K. Swanke

Ms. Swanke has served as an executive employee since September 17, 2003, pursuant to an employment agreement dated September 17, 2003, and a letter agreement dated July 1, 2004. The term of Ms. Swanke’s employment agreement was indefinite until terminated by us, with or without cause, upon 30 days’ notice or by Ms. Swanke upon 180 days written notice; provided that we could terminate the agreement with cause without prior notice. The agreement also

terminated automatically upon Ms. Swanke’s death or disability. Ms. Swanke’s letter agreement included non-compete and confidentiality provisions. Ms. Swanke executed a Participation Agreement and Waiver on February 28, 2006, whereby she agreed to terminate her employment agreement and participate in the new executive compensation and benefits program previously described.

Compensation

Ms. Swanke’s employment agreement provided for (i) an annual base salary of not less than $230,000; (ii) participation in such short-term and long-term bonus, incentive compensation, deferred compensation and similar plans as we or the Compensation Committee determined; and (iii) such fringe benefits as are generally made available to all other employees, the Executive Medical Plan, the annual physical program and financial planning services in effect from time to time.

Termination

If Ms. Swanke’s employment was terminated without cause and she was not entitled to receive the benefits described below, then the agreement provided for payment of her annual base salary in installments over the one-year period after the date of termination; provided that Ms. Swanke executed and delivered a release pursuant to which she fully and unconditionally released any claims that she had against us and our affiliates. The definition of “cause” is identical to the definition provided in Mr. Wolff’s employment agreement summary as set forth herein.

If Ms. Swanke’s employment was terminated for any reason at any time, her letter agreement provided for (i) a lump sum cash payment equal to her full base salary through the date of termination; (ii) the amount of the awards, with respect to any completed period which, pursuant to the MICP or any other incentive plan (other than any deferred compensation plan in which she made a contrary installment election) that were earned but not paid; and (iii) payment of any other accrued benefits to which she was entitled through the date of termination.

For a period of one year after termination of Ms. Swanke’s employment, Ms. Swanke’s employment agreements stated that Ms. Swanke was required to provide assistance as may be necessary to facilitate a smooth and orderly transition of duties.

Change of Control

If Ms. Swanke’s employment was terminated in connection with a change of control, her letter agreement dated July 1, 2004, provided for payments and benefits similar to those described for Mr. Wolff as described herein, except that Ms. Swanke’s non-compete provisions were effective for three years after termination, whereas Mr. Wolff’s non-compete provisions were effective for two years after termination.

W. Steven Wolff

Mr. Wolff has served as our executive employee since September 17, 2003, pursuant to an employment agreement dated September 17, 2003, and a letter agreement dated November 1, 2002. The term of Mr. Wolff’s employment agreement was indefinite until terminated by us, with or without cause, upon 30 days’ notice or by Mr. Wolff upon 180 days’ written notice; provided that we could terminate the agreement with cause without prior notice. The agreement also terminated automatically upon Mr. Wolff’s death or disability. Mr. Wolff executed a Participation Agreement and Waiver on February 24, 2006, whereby he agreed to terminate his employment agreement and participate in the new executive compensation and benefits program previously described.

Compensation

Mr. Wolff’s agreement provided for (i) an annual base salary of not less than $250,000; (ii) participation in such short-term and long-term bonus, incentive compensation, deferred compensation and similar plans as we or the Compensation Committee determined; and (iii) such fringe benefits as were generally made available to all other employees, the Executive Medical Plan, the annual physical program and financial planning services in effect from time to time.

Termination

If Mr. Wolff’s employment was terminated without “cause” and he was not entitled to receive the benefits described below, then the agreement provided for payment of his annual base salary in installments over the one-year period after the date of termination; provided that Mr. Wolff executed and delivered a release pursuant to which he fully and unconditionally released any claims he had against us and our affiliates.

“Cause” for purposes of Mr. Wolff’s employment agreement was defined as (i) commission of a felony; (ii) embezzlement; (iii) the illegal use of drugs; or (iv) the failure by Mr. Wolff to substantially perform his duties hereunder (other than any such failure resulting from his physical or mental illness or other physical or mental incapacity) as reasonably determined by us.

If Mr. Wolff’s employment was terminated for any reason at any time, his letter agreement provided for (i) a lump sum cash payment to Mr. Wolff equal to his full base salary through the date of termination; (ii) the amount of the awards, with respect to any completed period, which pursuant to the MICP or any other incentive plan (other than any deferred compensation plan in which he made a contrary installment election) had been earned but not paid; and (iii) payment of any other accrued benefits to which he was entitled through the date of termination.

For a period of one year after termination of Mr. Wolff’s employment, Mr. Wolff’s employment agreement stated that Mr. Wolff was required to provide assistance as necessary to facilitate a smooth and orderly transition of duties.

Change of Control

If Mr. Wolff’s employment was terminated within 36 months of a change of control, Mr. Wolff’s letter agreement provided for (i) a lump sum cash payment equal to the sum of (a) the average of the three highest of the last ten annual award payments made pursuant to the MICP or other incentive plan, including any portion deferred to his deferred compensation plan account, if the termination preceded the actual determination of such incentive compensation or the completion of a period in which he could have earned incentive compensation; (b) an amount equal to 200% of the sum of his annual base salary, before deduction of any deferred amounts, and the average of the three highest of the last ten annual award payments made under the MICP, including any portion deferred to his deferred compensation plan account; (c) one-half of the amount payable in clause (b) in consideration of Mr. Wolff’s agreement to non-compete and confidentiality provisions; (d) any cash or shares of our common stock previously earned under the MICP or pursuant to action by the Board of Directors but not yet paid; (e) gross-up payments for excise taxes; and (ii) continuation of all life, medical, accident and disability insurance for Mr. Wolff and his eligible dependents until the third anniversary of the date of

termination or the date an essentially equivalent benefit was made available to Mr. Wolff by a subsequent employer.

Mr. Wolff’s letter agreement stated that the benefits described above would not be available if such termination is by (i) us or DPL for cause or on account of Mr. Wolff’s disability; (ii) Mr. Wolff without “good reason” and the change of control did not result from the commencement of a tender offer or us or DPL entering into an agreement to merge or consolidate or to sell, lease, exchange or otherwise transfer or dispose of all or substantially all of our assets; (iii) Mr. Wolff for any reason and the change of control resulted from the commencement of a tender offer or us or DPL entering into an agreement to merge or consolidate or to sell, lease, exchange or otherwise transfer or dispose of all or substantially all of its assets; or (iv) Mr. Wolff’s death. “Good Reason” for Mr. Wolff was defined as (i) assignment of duties inconsistent with the written objectives of his position, a change in his reporting responsibilities, his removal from or any failure to re-elect Mr. Wolff to his position or office; (ii) failure to have his annual base salary raised when salary adjustments are historically made; (iii) a reduction in his base salary; (iv) failure by us or DPL to continue a benefit plan, including incentive plans; (v) the relocation of our principal executive offices outside of Montgomery County, Ohio, if at the time of a change of control, Mr. Wolff was based at the principal offices; (vi) being required to base more than fifty miles from the location he was based at the time of the change of control or the failure to reimburse for moving expenses if Mr. Wolff consented to moving his base and permanent residence; (vii) excessive travel that necessitated overnight absences; (viii) the failure by us or DPL to obtain the assumption of his agreement by any successor; (ix) termination without cause or without being provided with a notice of termination; and (x) if, within 36 months of a change of control, Mr. Wolff determined that he could not effectively discharge his duties.

Upon a change of control, Mr. Wolff’s letter agreement stated that we and DPL would transfer cash or other property in an amount sufficient to fund all change of control benefits and payments to the master trust. In addition, the letter agreement provided a gross-up payment if any excise tax was imposed upon a change of control such that Mr. Wolff was in the same after-tax position as if no excise tax was imposed.

If Mr. Wolff’s employment was terminated within 36 months of a change in control due to his disability, his letter agreement provided for benefits under our and DPL’s salary continuation plan or disability insurance. If Mr. Wolff’s employment was terminated for cause subsequent to a change of control, his letter agreement provided for compensation for services previously rendered as if he were terminated without the occurrence of a change of control.

Further, if a tender offer or a potential agreement was abandoned or terminated and a majority of the original directors and/or their successors determined that the tender offer or agreement would not effectuate or otherwise result in a change of control and provided written notice of such determination, then a subsequent termination would not entitle Mr. Wolff to the benefits described above.

Compensation of Directors

In 2005, director compensation for each non-employee director consisted of an annual retainer of $55,000 (for service on our Board and the DPL Board), a committee chair retainer of $10,000, Board meeting fees of $5,000 per meeting, committee meeting fees of $4,000 per meeting and a special meeting fee of $3,000 per meeting. Director compensation retainer, committee chair and meeting fees have remained unchanged from 2003 through 2005.

DPL maintains a Director Deferred Compensation Plan in which payment of directors’ fees may be deferred. The director fees of those directors who have designated their director fees to be deferred are invested in DPL common share units. Under the Director Deferred Compensation Plan, directors are entitled to receive a lump sum payment or payments in installments over a period of up to 20 years upon their retirement or resignation from the Board.

Compensation Committee

DPL’s Compensation Committee makes recommendations to our Board to (i) set compensation levels for officers, (ii) approve equity incentive and other benefit plans and (iii) negotiate and approve executive level employment and consulting contracts. DPL’s revised Charter of Compensation Committee, which describes all of the Compensation Committee’s responsibilities, is posted on DPL’s website.

The Compensation Committee is currently comprised of the following independent directors: Paul R. Bishop, Chair; Barbara S. Graham, Vice Chair; Glenn E. Harder; W August Hillenbrand; and Lester L. Lyles. Our Board has determined that each member of the Compensation Committee meets the independence requirements of Section 162(m) of the Internal Revenue Code. No member of the Compensation Committee serves, or has served, as an officer or employee of the Company or DPL. In addition, no interlocking relationship exists between our Board or DPL’s Board or Compensation Committee and the board of directors or compensation committee of any other company, nor has any such interlocking relationship existed in the past.

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

Equity Compensation Plan Information

The following table sets forth certain information as of December 31, 2005, with respect to the Company’s or DPL’s equity compensation plans under which shares of DPL’s equity securities may be issued.

	(a)		(b)		(c)
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans excluding securities reflected in column (a)
Equity compensation plan approved by security holders:

DPL Inc. Stock Option Plan	5,486,500 (4	)	$	21.86	1,488,500

Equity compensation plans not approved by security holders:

Directors’ Deferred Stock Compensation Plan (1)	438,106		N/A		See Notes (1) and (3	)

Management Stock Incentive Plan (2)	1,237,905 (4	)	N/A		0 (2) and (3	)

Total	7,162,511

(1) The Directors’ Deferred Stock Compensation Plan (the Directors’ Stock Plan) provided for the annual award of DPL common shares to non-employee directors for services as a director. All shares awarded under the Directors’ Stock Plan are transferred to the Master Trust. The Directors’ Stock Plan does not have a stated maximum number of shares.

(2) The Management Stock Incentive Plan provided for the award of SIUs to executives. Earning of SIUs was dependent on the achievement of long-term incentives, including DPL’s performance over various performance periods. For each SIU that was earned and vested, a participant received the equivalent of one DPL common share plus dividend equivalents from the date of award. New awards under the Management Stock Incentive Plan were discontinued in 2000 upon approval of the Stock Option Plan.

(3) We have secured our obligations under the Directors’ Deferred Stock Compensation Plan and the Management Stock Incentive Plan by market purchases of our common shares by the Master Trust. Accordingly, issuance of shares to directors or executives under these plans will not increase the number of DPL common shares issued.

(4) Included under both the Stock Option Plan and the Management Stock Incentive Plan are options and SIUs awarded to Peter H. Forster, former Chairman; Stephen F. Koziar, former President and Chief Executive Officer and Caroline E. Mahlenkamp, Former Group Vice President and interim Chief Financial Officer. We have initiated legal proceedings to challenge the validity of any options and SIUs awarded.

Security Ownership of Management

Set forth below is information concerning the beneficial ownership of DPL’s common shares by each director, each person named in the Summary Compensation Table under “Executive Compensation” below and of all our directors and executive officers as a group as of March 3, 2006.

Name	Amount and Nature of Beneficial Ownership	Percent of Class (1) (2) (3)
Robert D. Biggs	102,563	<1%
Paul R. Bishop	29,031	<1%
John J. Gillen	10,232	<1%
Barbara S. Graham	1,293	<1%
Ernie Green	182,668	<1%
Glenn E. Harder	2,646	<1%
W August Hillenbrand	195,574	<1%
Lester L. Lyles	6,375	<1%
James V. Mahoney	80,157	<1%
Ned J. Sifferlen	13,764	<1%
Patricia K. Swanke	54,659	<1%
W. Steven Wolff	1,589	<1%
All current directors and executive officers as a group (15 persons) (4)	734,940	<1%

(1) Ownership percentages are based on 125,949,404 common shares outstanding as of March 3, 2006.

(2) The number of shares shown represents in each instance <1% of DPL’s outstanding common shares. There were 734,940 common shares and common share units, or <1% of the total number of common shares, beneficially owned by all directors and executive officers of DPL and DP&L as a group at March 3, 2006. The number of shares shown includes (i) 65,072 common shares transferred to the Master Trust for non-employee directors pursuant to the Directors’ Deferred Stock Compensation Plan, (ii) 100,000 common shares subject to presently exercisable options for current non-employee directors, and (iii) 217,794 share units with no voting rights held by non-employee directors under the Directors’ Deferred Compensation Plan as follows: Mr. Biggs – 2,563 units (for share units acquired by Mr. Biggs as a non-employee director from February 2004 to May 2004); Mr. Bishop – 29,031 units; Ms. Graham – 1,293 units; Mr. Green – 80,865 units; Mr. Harder 2,646 units; Mr. Hillenbrand – 84,557 units; Mr. Lyles – 6,375 units; and Dr. Sifferlen – 10,464 units.

(3) The number of shares shown includes common shares, restricted share units with no voting rights, and stock options that are exercisable.

(4) These 15 persons include all current directors and executive officers listed under “Information About the Nominees, the Continuing Directors and Executive Officers” below.

Item 13 – Principal Accountant Fees and Services

The following table presents the aggregate fees billed for professional services rendered to us and DPL by KPMG LLP for 2005 and 2004. Other than as set forth below, no professional services were rendered or fees billed by KPMG LLP and PricewaterhouseCoopers LLP during 2005 and 2004.

KPMG LLP	Fees Paid 2005		Fees Paid 2004
Audit Services (1)	$	2,511,912	$	2,498,189
Audit-Related Services (2)	55,712		147,136
Tax Services (3)	2,435		62,966
All Other Services (4)	—		—
Total	$	2,570,059	$	2,708,291

PricewaterhouseCoopers LLP
Audit Services (1)	$	96,350	$	770,074
Audit-Related Services (2)	14,400		—
Tax Services (3)	—		—
All Other Services (4)	—		—
Total	$	110,750	$	770,074

(1) Audit services consist of professional services rendered for the audit of our annual financial statements and the reviews of our quarterly financial statements.

(2) Audit-related services are those rendered to us for assurance and related services.

(3) Tax services are those rendered to us for tax compliance, tax planning and advice.

(4) Other services performed include certain advisory services in connection with accounting research and do not include any fees for financial information systems design and implementation.

Pre-Approval Policies and Procedures of the Audit Committee

Pursuant to its charter, the Audit Committee pre-approves all audit and permitted non-audit services, including engagement fees and terms thereof, to be performed for us by the independent auditors, subject to the exceptions for certain non-audit services that are approved by the Audit Committee prior to the completion of the audit in accordance with Section 10A of the Securities Exchange Act of 1934, as amended. The Audit Committee must also pre-approve all internal control-related services to be provided by the independent auditors. The Audit Committee will generally pre-approve a list of specific services and categories of services, including audit, audit-related and other services, for the upcoming or current fiscal year, subject to a specified cost level. Any material service that is not included in the approved list of services must be separately pre-approved by the Audit Committee. In addition, all audit and permissible non-audit services in excess of the pre-approved cost level, whether or not such services are included on the pre-approved list of services, must be separately pre-approved by the Audit Committee.

The Audit Committee may form and delegate to a subcommittee consisting of one or more members (provided that such person(s) are independent directors) its authority to grant pre-approvals of audit, permitted non-audit services and internal control-related services, provided that decisions of such subcommittee to grant pre-approvals shall be presented to the full Audit Committee at its next scheduled meeting.

PART IV

Item 15 - Exhibits, Financial Statement Schedule and Reports on Form 8-K

	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	31
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2005	32
Consolidated Balance Sheets at December 31, 2005 and 2004	33
Consolidated Statement of Changes to Shareholders’ Equity for each of the three years in the period ended December 31, 2005	35
Notes to Consolidated Financial Statements	36
Report of Independent Registered Public Accounting Firm	69
Report of Independent Registered Public Accounting Firm on Internal Controls	70

2. Financial Statement Schedule

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

Schedule II – Valuation and Qualifying Accounts	99

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 The Dayton Power and Light Company dated January 4, 1991	Exhibit 3(b) to Report on Form 10-K for the year ended December 31, 1991 (File No. 1-2385)

3(b)	Regulations of The Dayton Power and Light Company	Exhibit 3(a) to Report on Form 8-K filed on May 3, 2004 (File No. 1-2385)

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 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 (g)	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)

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 to Directors’ 1991 Amended Deferred Compensation Plan as amended through December 31, 2000 and dated as of December 7, 2004	Exhibit 10(c) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

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 to Management Stock Incentive Plan amended December 31, 2000 and dated as of December 7, 2004	Exhibit 10(e) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

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 to Key Employees Deferred Compensation Plan amended December 31, 2000 and dated as of December 7, 2004	Exhibit 10(g) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

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 to Supplemental Executive Retirement Plan amended February 1, 2000 and dated as of December 7, 2004	Exhibit 10(i) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

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	Exhibit 10(l) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

10(m)*	Summary of Executive Medical Insurance Plan	Exhibit 10(m) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

10(n)*	Copy of Executive Compensation and Benefits Program dated as of February 23, 2006	Exhibit 10.1 to Report on Form 8-K/A filed on March 2, 2006 (File No. 1-2386)

10(o)*	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(p)*	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(q)*	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(r) *	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(s)*	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(t)*	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(u)*	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(v)*	Management Stock Option Agreement dated as of December 29, 2004 between DPL Inc. and John J. Gillen	Exhibit 10(s) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

10(w)*	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(x)*	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(y)*	Employment agreement dated as of December 17, 2003, between DPL Inc. and Patricia K. Swanke	Exhibit 10(l) to Report on Form 10-K for the year ended December 31, 2003 (File No.1-9052)

10(z)*	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(aa)*	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(bb)*	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(cc)*	Change of Control Agreement dated as of December 15, 2000 between DPL Inc., The Dayton Power and Light Company and Arthur G. Meyer	Exhibit 10(z) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

10(dd)*	Management Stock Option Agreement dated as of January 1, 2001 between DPL Inc. and Arthur G. Meyer	Exhibit 10(aa) to Report on Form 10-K for the year ended December 31, 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 the Dayton Power and Light Company	Filed herewith as Exhibit 21

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

32(a)	Certification of Chief Executive 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(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 agree to furnish to the SEC on request any such instruments.

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.

	The Dayton Power and Light Company


March 1, 2006
By:	/s/ James V. Mahoney
	James V. Mahoney President and Chief Executive Officer (principal executive officer)

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	March 1, 2006
(R. D. Biggs)

/s/ P. R. Bishop	Director	March 1, 2006
(P. R. Bishop)

/s/ E. Green	Director	March 1, 2006
(E. Green)

/s/ G.E. Harder	Director	March 1, 2006
(G. E. Harder)

/s/ W.A. Hillenbrand	Director and Vice-Chairman	March 1, 2006
(W A. Hillenbrand)

/s/ L.L. Lyles
(L. L. Lyles)	Director	March 1, 2006

/s/ J. V. Mahoney	Director, President and Chief	March 1, 2006
(J. V. Mahoney)	Executive Officer (principal executive officer)

/s/ N. J. Sifferlen
(N. J. Sifferlen)	Director	March 1, 2006

/s/ J. J. Gillen	Senior Vice President and	March 1, 2006
(J. J. Gillen)	Chief Financial Officer (principal financial and principal accounting officer)

/s/ D. L. Thobe	Corporate Controller	March 1, 2006
(D. L. Thobe)

Schedule II

The Dayton Power and Light Company

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	$	3,617	$	885	$	3,417	$	1,085

2003:
Deducted from accounts receivable—

Provision for uncollectible accounts	$	10,873	$	4,463	$	11,719	$	3,617

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

EX-21 2 a06-2289_1ex21.htm SUBSIDIARIES OF THE REGISTRANT

Exhibit 21

SUBSIDIARIES OF THE DAYTON POWER AND LIGHT COMPANY

The Dayton Power and Light Company had the following significant subsidiary on December 31, 2005:

	State of Incorporation
DPL Finance Company, Inc.	Delaware

EX-31.(A) 3 a06-2289_1ex31da.htm 302 CERTIFICATION

Exhibit 31(a)

CERTIFICATIONS

I, James V. Mahoney, certify that:

1. I have reviewed this annual report on Form 10-K of The Dayton Power and Light Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 27, 2006

	/s/ James V. Mahoney
	James V. Mahoney
	President and Chief Executive Officer

EX-31.(B) 4 a06-2289_1ex31db.htm 302 CERTIFICATION

Exhibit 31(b)

CERTIFICATIONS

I, John J. Gillen, certify that:

1. I have reviewed this annual report on Form 10-K of The Dayton Power and Light Company;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 27, 2006

	/s/ John J. Gillen
	John J. Gillen
	Senior Vice President and Chief Financial Officer

EX-32.(A) 5 a06-2289_1ex32da.htm 906 CERTIFICATION

Exhibit 32(a)

THE DAYTON POWER AND LIGHT COMPANY

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO
SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

The undersigned officer of The Dayton Power and Light Company (the “Issuer”) hereby certify that the Issuer’s Annual Report on Form 10-K for the period ended December 31, 2005, which this certificate accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Issuer.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this statement required by Section 906, has been provided to the Issuer and will be retained by the Issuer and furnished to the Securities and Exchange Commission or its staff upon request.

Signed:

/s/ James V. Mahoney
James V. Mahoney
President and Chief Executive Officer

Date: March 1, 2006

The foregoing certificate is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as a part of the Issuer’s Annual Report or as a separate disclosure document.

EX-32.(B) 6 a06-2289_1ex32db.htm 906 CERTIFICATION

Exhibit 32(b)

THE DAYTON POWER AND LIGHT COMPANY

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO
SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

Signed:

/s/ John J. Gillen
John J. Gillen
Senior Vice President and Chief Financial Officer

Date: March 1, 2006

The foregoing certificate is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as a part of the Issuer’s Annual Report or as a separate disclosure document.

-----END PRIVACY-ENHANCED MESSAGE-----

Fiscal Year Ended December 31, 2005

Available Information

PART I

Margins, Fuel and Purchased Power

Investment Income

Income Tax Expense

Cumulative Effect of Accounting Change, Net of Tax

LEGAL AND OTHER MATTERS

Revenues

Depreciation

Asset Retirement Obligations

Emission Allowances

Repairs and Maintenance

Financial Derivatives

Pre-Approval Policies and Procedures of the Audit Committee

Schedule II – Valuation and Qualifying Accounts

99

State of Incorporation