UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________ to ________

Commission File Number 1-2385

THE DAYTON POWER AND LIGHT COMPANY
(Exact name of registrant as specified in its charter)

OHIO
(State or other jurisdiction of
incorporation or organization)

31-0258470
(I.R.S. Employer Identification No.)

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

45432
(Zip Code)

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

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

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

Indicate by check mark if 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. ____

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 |X| NO |_|

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 126-2).

YES |X| NO |_|

Number of shares of registrant’s common stock outstanding as of December 31, 2002, all of which were held by DPL Inc., was 41,172,173.

THE DAYTON POWER AND LIGHT COMPANY

Index to Annual Report on Form 10-K
Fiscal Year Ended December 31, 2002

		Page No
	Part I

Item 1	Business		3
Item 2	Properties		16
Item 3	Legal Proceedings		16
Item 4	Submission of Matters to a Vote of Security Holders		16

	Part II

Item 5	Market for Registrant’s Common Equity and Related Shareholder Matters		17
Item 6	Selected Financial Data		17
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
Item 7A	Quantitative and Qualitative Disclosure about Market Risk		32
Item 8	Financial Statements and Supplementary Data		33
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		58

	Part III

Item 10	Directors and Executive Officers of the Registrant		58
Item 11	Executive Compensation		62
Item 12	Security Ownership of Certain Beneficial Owners and Management		67
Item 13	Certain Relationships and Related Transactions		67
Item 14	Controls and Procedures		68

	Part IV

Item 15	Exhibits, Financial Statement Schedules and Reports on Form 8-K		68

	Other

	Signatures		72
	Certifications		74

PART I

Item 1 — Business

THE COMPANY

The Dayton Power and Light Company (“DP&L” or “the Company”) is a public utility incorporated under the laws of Ohio in 1911. The Company sells electricity to residential, commercial, industrial, and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for the Company’s 24 county service area is generated at eight power plants and is distributed to more than 500,000 retail customers. Principal industries served include automotive, food processing, paper, technology, and defense. The Company’s sales reflect the general economic conditions and seasonal weather patterns of the area.

The Company employed 1,464 persons as of December 31, 2002, of which 1,217 were full-time employees and 247 were part-time employees.

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

The Company’s principal executive and business office is located at 1065 Woodman Drive, Dayton, Ohio 45432 — telephone (937) 224-6000.

COMPETITION

In October 1999, legislation became effective in Ohio that gave electric utility customers a choice of energy providers as of January 1, 2001. Under the legislation, electric generation, aggregation, power marketing, and power brokerage services supplied to retail customers in Ohio is deemed to be competitive and is not subject to supervision and regulation by the Public Utilities Commission of Ohio (“PUCO”). As required by the legislation, the Company filed its transition plan at the PUCO on December 20, 1999. The Company received PUCO approval of its plan on September 21, 2000.

The transition plan provides for a three-year transition period, which began on January 1, 2001 and ends on December 31, 2003. The plan also provides for a 5% residential rate reduction on the generation component of the rates, which reduced annual revenue by approximately $14 million; rate certainty for the three year period for customers that continue to purchase power from the Company; guaranteed rates for a six-year period for transmission and delivery services; and recovery of transition costs of approximately $600 million. Under the plan, the Company has the organizational and financial flexibility to continue its growth initiatives.

On October 28, 2002, DP&L filed with the PUCO requesting an extension of its market development period from December 31, 2003 to December 31, 2005. If approved by the PUCO, the extension of the market development period will continue DP&L’s current rate structure and provide its retail customers with rate stability. It is unknown when the PUCO will rule on this request.

On September 30, 1996, the Federal Energy Regulatory Commission (“FERC”) conditionally accepted the Company’s market-based sales tariff, which allowed the Company to sell wholesale generation supply at prices that reflect current market prices. On September 27, 2002, DP&L filed an updated market power analysis with the FERC in support of its authority to sell power at market-based rates.

The Company competes with privately and municipally owned electric utilities and rural electric cooperatives, and other alternate fuel suppliers on the basis of price and service. The Company purchases generation capacity from DPL Energy, LLC, a wholly owned subsidiary of DPL.

Like other utilities and energy marketers, the Company from time to time may have electric generating capacity available for sale on the wholesale market. The Company competes with other generators to sell electricity provided by such capacity. The ability of the Company to sell this electricity will depend on how the Company’s price, terms and conditions compare to those of other suppliers. In addition, from time to time, the Company makes power purchases from other suppliers.

The Company provides transmission and wholesale electric service to twelve municipal customers which distribute electricity within their corporate limits. In addition to these municipal customers, the Company maintains an interconnection agreement with one municipality that has the capability to generate a portion of its energy requirements. Sales to municipalities represented 1.2% of total electricity sales in 2002.

The municipal agreements provide, among other things, for the sale of firm power by the Company to the municipalities on specified terms. However, the parties disagree in their interpretation of this portion of the agreement and the Company filed suit against the eleven municipalities on December 28, 1998. The dispute was subsequently settled in 1999. In December 1999, the Company filed a second suit against the municipalities to claim the municipalities’ initial failure to pay for certain services rendered under the contract. The municipalities filed a complaint at the FERC claiming violation of a mediation clause. On November 4, 2002, the FERC issued an order in the case that was favorable to DP&L, and is not expected to result in a material impact on DP&L’s financial position.

The FERC issued a final rule on December 20, 1999 specifying the minimum characteristics and functions for Regional Transmission Organizations (“RTO”). The rule required that all public utilities that own, operate or control interstate transmission lines file a proposal to join an RTO by October 15, 2000 or file a description of efforts taken to participate in an RTO, reasons for not participating in an RTO, any obstacles to participation in an RTO, and any plans for further work towards participation. The Company filed with the FERC on October 16, 2000 to join the Alliance RTO. On December 19, 2001, the FERC issued an order rejecting the Alliance RTO as a stand-alone RTO. However, on April 24, 2002, the FERC approved the Alliance RTO companies’ proposal to form an independent transmission company that will operate under the umbrella of an existing RTO. As of December 31, 2002, the Company had invested approximately $8 million in its efforts to join the Alliance RTO. The FERC recognized in its order that substantial losses were incurred to establish the Alliance RTO and that it would consider proposals for rate recovery of prudently incurred costs.

On May 28, 2002, the Company filed a notice with the FERC stating its intention to join the PJM Interconnection, L.L.C. (“PJM”), an organization responsible for the operation and control of the bulk electric power system throughout major portions of five Mid-Atlantic states and the District of Columbia. On July 31, 2002, the FERC granted the Company conditional approval to join PJM. On September 30, 2002, the Company signed an implementation agreement with PJM with the expectation that the Company will be fully integrated into the PJM market by May 1, 2003. On December 11, 2002, the Company executed the PJM West Transmission Owners Agreement and along with the other new PJM companies, jointly submitted the PJM Open Access Transmission Tariff (“OATT”) filing. This filing adopts a transitional rate design that will maintain revenue and cost neutrality while eliminating all seams within the newly expanded PJM.

On September 12, 2002, the Ohio Consumers’ Counsel, Industrial Energy Users-Ohio and American Municipal Power-Ohio, Inc. filed a complaint with the PUCO alleging that the Company had failed to join and transfer operational control to a FERC approved RTO. The Company filed a motion to dismiss the complaint on October 24, 2002. While the Company intends to vigorously defend this case, the impact of the complaint cannot be determined at this time.

On July 31, 2002, the FERC issued a Standard Market Design Notice of Proposed Rulemaking (“SMD NOPR”). The SMD NOPR establishes a set of rules to standardize wholesale electric market design to create wholesale competition and efficient transmission systems. The impact of this rulemaking on the Company cannot be determined at this time.

On July 22, 1998, the PUCO approved the implementation of Minimum Electric Service and Safety Standards for all of Ohio’s investor-owned electric utilities. This order details minimum standards of performance for a variety of service related functions effective July 1, 1999. On December 21, 1999, the PUCO issued additional rules proposed by the PUCO staff, which were designed to guide the electric utility companies as they prepare to enter into deregulation. These rules include certification of providers of competitive retail electric services, minimum competitive retail electric service standards, monitoring the electric utility market, and establishing procedures for alternative dispute resolution. There were also rules issued to amend existing rules for noncompetitive electric service and safety standards and electric companies long-term forecast reporting. The Company submitted comments on the proposed rules on January 31, 2000. The rules were finalized by the PUCO in June 2000 and did not have a material impact on the Company’s financial position.

On March 21, 2002, the PUCO staff proposed modifications to the Minimum Electric Service and Safety Standards, which establish performance standards for various service related functions of investor-owned electric utilities. The proposed modifications impact billing, collections, allocation of customer payments, meter reading, and distribution circuit performance. The Company submitted comments and reply comments on the proposed rules, and filed an application for rehearing on October 26, 2002. The PUCO issued the final rules on September 26, 2002, but has granted applications for rehearing to provide more time for rule review. The cost to the Company of compliance with these rules is unknown at this time.

CONSTRUCTION PROGRAM

Construction additions are expected to approximate $109 million in 2003, and were $129 million 2002 and $164 million in 2001. The capital program includes environmental compliance, which is expected to approximate $39 million in 2003, and was $69 and $58 million in 2002 and 2001, respectively.

Construction plans are subject to continuing review and are expected to be revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental standards, among other factors. The Company’s ability to complete its capital projects and the reliability of future service will be affected by its financial condition, the availability of external funds at reasonable cost and adequate and timely rate recovery. The Company expects to finance its construction program in 2003 with internal funds.

See ENVIRONMENTAL CONSIDERATIONS for a description of environmental control projects and regulatory proceedings, which may change the level of future construction additions. The potential impact of these events on the Company’s operations cannot be estimated at this time.

ELECTRIC OPERATIONS AND FUEL SUPPLY

The Company’s present winter generating capability is 3,371,000 KW. Of this capability, 2,843,000 KW (approximately 84%) is derived from coal-fired steam generating stations and the balance consists of combustion turbine and diesel-powered peaking units. Approximately 87% (2,472,000 KW) of the existing steam generating capability is provided by certain units owned as tenants in common with The Cincinnati Gas & Electric Company (“CG&E”) or with CG&E and Columbus Southern Power Company (“CSP”). 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.

The remaining steam generating capability (371,000 KW) is derived from a generating station owned solely by the Company. The Company’s all-time net peak load was 3,130,000 KW, occurring in 1999. The present summer generating capability is 3,269,000 KW.

				MW Rating
Station	Ownership*	Operating Company	Location	Company Portion	Total
Coal Units

Hutchings	W	Company	Miamisburg, OH	371	371
Killen	C	Company	Wrightsville, OH	402	600
Stuart	C	Company	Aberdeen, OH	820	2,340
Conesville-Unit 4	C	CSP	Conesville, OH	129	780
Beckjord-Unit 6	C	CG&E	New Richmond, OH	210	420
Miami Fort-Units 7 & 8	C	CG&E	North Bend, OH	360	1,000
East Bend-Unit 2	C	CG&E	Rabbit Hash, KY	186	600
Zimmer	C	CG&E	Moscow, OH	365	1,300

Combustion Turbines or Diesel

Hutchings	W	Company	Miamisburg, OH	33	33
Yankee Street	W	Company	Centerville, OH	138	138
Monument	W	Company	Dayton, OH	12	12
Tait	W	Company	Dayton, OH	10	10
Sidney	W	Company	Sidney, OH	12	12
Tait Gas Turbines 1-3	W	Company	Moraine, OH	304	304
Killen	C	Company	Wrightsville, OH	16	24
Stuart	C	Company	Aberdeen, OH	3	10

*W = Wholly-Owned
C = Commonly Owned

In order to transmit energy to their respective systems from their commonly owned generating units, the companies have constructed and own, as tenants in common, 847 circuit miles of 345,000-volt transmission lines. The Company has several interconnections with other companies for the purchase, sale and interchange of electricity. In July 2001, the Company completed a 40.2-mile long, 345,000-volt circuit between CG&E’s Foster Substation and DP&L’s Bath Substation. The circuit is jointly owned by DP&L and CG&E.

The Company generated over 97% of its electric output from coal-fired units in 2002. The remainder was from oil or natural gas-fired units, which were used to meet peak demands.

The Company has contracted approximately 95% of its total coal requirements for 2003 with the balance to be obtained by spot market purchases. The prices to be paid by the Company under its long-term coal contracts are subject to adjustment in accordance with various indices. Each contract has features that will limit price escalations in any given year.

The average fuel cost per kilowatt-hour (“kWh”) generated of fuel burned for electric generation (coal, gas and oil) for the year was 1.26¢ in 2002, 1.31¢ in 2001, and 1.18¢ in 2000. With the onset of competition in January 2001, the Electric Fuel Component became part of the Standard Offer Generation Rate. See RATE REGULATION AND GOVERNMENT LEGISLATION and ENVIRONMENTAL CONSIDERATIONS.

GAS OPERATIONS AND GAS SUPPLY

In October 2000, the Company completed the sale of its natural gas retail distribution assets and certain liabilities for $468 million in cash. The transaction resulted in a pre-tax gain of $183 million ($121 million net of taxes). Proceeds from the sale were used to finance DPL’s regional generation expansion and reduce outstanding short-term debt.

RATE REGULATION AND GOVERNMENT LEGISLATION

The Company’s sales to retail customers are subject to rate regulation by the PUCO and various municipalities. The Company’s wholesale electric rates to municipal corporations and other distributors of electric energy are subject to regulation by the FERC under the Federal Power Act.

Ohio law establishes the process for determining rates charged by public utilities. Regulation of rates encompasses the timing of applications, the effective date of rate increases, the cost basis upon which the rates are based and other related matters. Ohio law also establishes the Office of the Ohio Consumers’ Counsel (the “OCC”), which has the authority to represent residential consumers in state and federal judicial and administrative rate proceedings.

Ohio legislation extends the jurisdiction of the PUCO to the records and accounts of certain public utility holding company systems, including DPL. The legislation extends the PUCO’s supervisory powers to a holding company system’s general condition and capitalization, among other matters, to the extent that they relate to the costs associated with the provision of public utility service.

Based on existing regulatory authorization, regulatory assets on the Consolidated Balance Sheet include:

	At December 31,
($ in millions)	2002		2001
Regulatory transition costs (a)	$	49.3	$	97.2
Income taxes recoverable through future revenues (b)		34.6		39.2
Other costs (b)		21.8		20.7

Total	$	105.7	$	157.1

(a) As discussed in the COMPETITION section, the Company received PUCO approval of its transition plan for the deregulation of its generation business. Accordingly, the Company discontinued the use of its regulatory accounting model for its generation operations. As a result, a $63.7 million before tax benefits ($41.4 million net of taxes) reduction of generation-related regulatory assets was recorded in the third quarter of 2000 as an extraordinary item and other generation-related regulatory assets were reclassified to the “Regulatory transition costs” asset.

(b) Certain deferred costs remain authorized for recovery by regulators. These relate primarily to the Company’s electric transmission and distribution operations and are being amortized over the recovery period of the assets involved.

Under the legislation passed in 1999, the percentage of income payment plan (“PIPP”) for eligible low-income households was converted to a universal service fund in 2001. The universal service program is administered by the Ohio Department of Development and provides for full recovery of arrearages for qualifying low income customers. As part of the Company’s Electric Transition Plan, the Company was granted authority to recover PIPP arrearages remaining as of December 31, 2000 as part of a transition charge.

In 2000, the PUCO amended the rules for Long-Term Forecast Reports for all investor-owned electric transmission and distribution companies in Ohio. Under these rules, each transmission and/or distribution company must annually file a Long-Term Electric Forecast Report, which presents 10-year energy and demand transmission and distribution forecasts. The reports also must contain information on the company’s existing and planned transmission and distribution systems, as well as a substantiation of the need for any system upgrades or additions. The Company filed a combined 2000/2001 Long-Term Electric Forecast Report under these amended rules in March 2001.

The PUCO is composed of five commissioners appointed to staggered five-year terms. The current Commission is composed of the following members:

Name	Beginning of Term	End of Term
Judith A. Jones	April 2002	April 2007
Clarence D. Rogers	February 2001	April 2006
Rhonda H. Fergus	April 2000	April 2005
Chairman Alan R. Schriber	April 1999	April 2004
Donald L. Mason	April 1998	April 2003

See COMPETITION for more detail regarding the impact of legislation passed in October 1999.

ENVIRONMENTAL CONSIDERATIONS

The operations of the Company, including the commonly owned facilities operated by the Company, CG&E and CSP, are subject to federal, state, and local regulation as to air and water quality, disposal of solid waste and other environmental matters, including the location, construction and initial operation of new electric generating facilities and most electric transmission lines. The possibility exists that current environmental regulations could be revised which could change the level of estimated construction expenditures. See CONSTRUCTION PROGRAM.

Air Quality

The Clean Air Act Amendments of 1990 (the “CAA”) have limited sulfur dioxide and nitrogen oxide emissions nationwide. The CAA restricts emissions in two phases. Phase I compliance requirements became effective on January 1, 1995 and Phase II requirements became effective on January 1, 2000.

The Company’s environmental compliance plan (“ECP”) was approved by the PUCO on May 6, 1993 and, on November 9, 1995, the PUCO approved the continued appropriateness of the ECP. Phase I requirements were met by switching to lower sulfur coal at several commonly owned electric generating facilities and increasing existing scrubber removal efficiency. Total capital expenditures to comply with Phase I of the CAA were approximately $5.5 million. Phase II requirements are being met primarily by switching to lower sulfur coal at all non-scrubbed coal-fired electric generating units.

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 CAA. Generation units operated by partners CG&E (Beckjord 6) and CSP (Conesville 4) and co-owned by the Company 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. The Company was not identified in the NOVs, civil complaints or state actions. In December 2000, CG&E announced that it had reached an Agreement in Principle with the USEPA and other plaintiffs in an effort to settle the claims. Discussions on the final terms of the settlement are ongoing. Therefore, it is not possible to determine the outcome of these claims or the impact, if any, on the Company. In June 2000, the USEPA issued a NOV to DP&L-operated J.M. Stuart Station (co-owned by the Company, CG&E, and CSP) for alleged violations of the CAA. The NOV contained allegations consistent with NOVs and complaints that the USEPA had previously brought against numerous other coal-fired utilities in the Midwest. The Company will vigorously challenge the NOV. At this time, it is not possible to determine the outcome of these claims or the impact, if any, on the Company.

On November 22, 2002, the USEPA announced its final rule package on New Source Review reform and its proposed rule on the definition of “routine maintenance, repair and replacement.” On December 31, 2002, the final and proposed rules were published in the Federal Register. Several northeast states have brought lawsuits challenging the final rule in the United States Court of Appeals for the District of Columbia. While the Company will conduct an extensive review of the published rules, it does not expect the rule changes to have a material effect on the Company’s financial position, earnings, or cash flow.

In September 1998, the USEPA issued a final rule requiring states to modify their State Implementation Plans (“SIPs”) under the CAA. The modified SIPs are likely to result in further nitrogen oxide (“NOx”) reduction requirements placed on coal-fired generating units by 2004. In order to meet these NOx requirements, the Company’s total capital expenditures are estimated to be approximately $175 million, of which $136 million has been spent to-date. Industry groups and others appealed the rules in United States District Court. The requirement for states to submit revised implementation plans has been stayed until the outcome of the litigation. In March 2000, the United States District Court upheld the rule. Industry groups and others have appealed this decision. As a result of the litigation, the Court extended the compliance date of the rule an additional year, until May 31, 2004. In March 2001, the United States Supreme Court refused to hear further appeals of the SIP rules. In December 1999, the USEPA issued final rules granting various CAA Section 126 petitions filed by northeast states. The Company’s facilities were identified, among many others, in the rulemaking. In January 2002, the USEPA announced that reductions required under the CAA Section 126 rulemaking will be extended until May 31, 2004 to be consistent with the NOx SIP rule. The Company’s current NOx reduction strategy and associated expenditures to meet the SIP call should satisfy the rulemaking reduction requirements.

On July 18, 2002, the Ohio Environmental Protection Agency (“Ohio EPA”) adopted rules that will constitute Ohio’s SIP for NOx reductions. The state rules are substantially similar to the reductions required under the federal CAA Section 126 rulemaking and federal NOx SIP rule. The USEPA has conditionally approved Ohio’s NOx SIP. On January 16, 2003, the USEPA’s final approval of Ohio’s NOx SIP appeared in the Federal Register. The Company’s current NOx reduction strategy and associated expenditures to meet the federal reduction requirements should satisfy the state SIP reduction requirements.

On December 14, 2000, the USEPA issued a determination that coal- and oil-fired electric generation units should be regulated for emissions of mercury and hazardous air pollutants. The USEPA will issue proposed rules by December 2003 and final rules by December 2004. The impact of the regulatory determination cannot be determined at this time.

In March 2002, the United States Court of Appeals for the District of Columbia upheld the USEPA’s National Ambient Air Quality Standards for ozone and fine particles. The USEPA is conducting a rulemaking regarding these standards. The impact of these standards and rules can not be determined at this time.

In April 2002, the USEPA issued proposed rules governing existing facilities that have cooling water intake structures. Final rules are anticipated in February 2004. The impact of the final rules cannot be determined at this time.

On July 29, 2002, the Bush Administration offered proposed legislation known as the “Clear Skies” initiative. The proposal calls for emissions reductions for sulfur dioxide, nitrogen oxides, and mercury commencing between 2008 and 2010. Senator Jeffords also offered a competing multi-pollutant proposal calling for reductions in sulfur dioxide, nitrogen oxides, mercury, and carbon dioxide emissions with earlier implementation dates. Neither proposal was passed in 2002. Several competing proposed bills revising the air pollution laws have emerged in the 108^th session of Congress. The impact of the potential legislation, if passed, cannot be determined at this time.

Land Use

The Company and numerous other parties have been notified by the USEPA or the Ohio Environmental Protection Agency (“Ohio EPA”) that it considers them Potentially Responsible Parties (“PRP’s”) for clean-up at three superfund sites in Ohio: the North Sanitary (a.k.a. Valleycrest) Landfill in Dayton, Montgomery County, Ohio; the Tremont City Landfill in Springfield, Ohio; and the South Dayton Dump landfill site in Dayton, Ohio.

The Company and numerous other parties received notification from the Ohio EPA on July 27, 1994 that it considers them PRP’s for clean up of hazardous substances at the North Sanitary Landfill site in Dayton, Ohio. The Company has not joined the PRP group formed for the site because the available information does not demonstrate that the Company contributed hazadous substances to the site. The Ohio EPA has not provided an estimated cost for this site. In October 2000, the PRP group brought an action against the Company and numerous other parties alleging that the Company and the others are PRP’s that should be liable for a portion of clean-up costs at the site. While the Company does not believe it disposed of any hazardous waste at this site, it has entered into an Agreement in Principle with the PRP group to settle any alleged liability for an immaterial amount. The final resolution is not expected to have a material effect on the Company’s financial position, earnings, or cash flow.

The Company and numerous other parties received notification from the USEPA in January 2002 for the Tremont City site. The available information does not demonstrate that the Company contributed any hazardous substances to the site. The Company will vigorously challenge this action. The final resolution is not expected to have a material effect on the Company’s financial position, earnings, or cash flow.

In September 2002, the Company and other parties received a special notice that the USEPA considers them to be PRP’s for the clean up of hazardous substances at the South Dayton Dump landfill site in Dayton, Ohio. The USEPA seeks recovery of past costs and funding for a Remedial Investigation and Feasibility Study. The USEPA has not provided an estimated clean-up cost for this site. The information available does not demonstrate that the Company contributed hazardous substances to the site. The Company will challenge this action. The final resolution is not expected to have a material effect on the Company’s financial position, earnings, or cash flow.

The Dayton Power and Light Company
OPERATING STATISTICS
ELECTRIC OPERATIONS

	Years Ended December 31
	2002		2001		2000
Electric Sales (millions of kWh)
Residential		5,302		4,909		4,816
Commercial		3,710		3,618		3,540
Industrial		4,472		4,568		4,851
Other retail		1,405		1,369		1,370

Total Retail		14,889		14,464		14,577
Wholesale		4,358		3,591		2,946


Total		19,247		18,055		17,523


Electric Revenues (thousands)
Residential	$	463,197	$	429,932	$	422,733
Commercial		259,496		255,149		245,097
Industrial		204,627		210,022		236,670
Other retail		95,463		92,992		93,227

Total Retail		1,022,783		988,095		997,727
Wholesale		153,055		200,154		112,328


Total	$	1,175,838	$	1,188,249	$	1,110,055


Electric Customers at End of Period
Residential		449,153		447,066		444,683
Commercial		47,400		46,815		46,218
Industrial		1,905		1,908		1,928
Other		6,304		6,318		6,156


Total		504,762		502,107		498,985

NOTE: See Note 13 to Consolidated Financial Statements for additional information.

The Dayton Power and Light Company
OPERATING STATISTICS
GAS OPERATIONS

	Years Ended December 31
	2002		2001		2000
Gas Sales (thousands of MCF)
Residential		—		—		18,538
Commercial		—		—		5,838
Industrial		—		—		2,034
Public authorities		—		—		776
Transportation gas delivered		—		—		16,105


Total		—		—		43,291


Gas Revenues (thousands)
Residential		—		—	$	119,460
Commercial		—		—		35,262
Industrial		—		—		11,114
Public authorities		—		—		4,466
Other		—		—		13,554


Total		—		—	$	183,856


Gas Customers at End of Period
Residential		—		—		—
Commercial		—		—		—
Industrial		—		—		—
Public authorities		—		—		—


Total		—		—		—

NOTE:
1)		The Company completed the sale of its natural gas retail distribution assets and certain liabilities in October 2000.

See Note 13 to Consolidated Financial Statements for additional information.

Item 2 — Properties

Electric

Information relating to the Company’s electric properties is contained in Item 1 — BUSINESS, THE COMPANY, CONSTRUCTION PROGRAM, ELECTRIC OPERATIONS AND FUEL SUPPLY, and Item 8 — Notes 4 and 11 of Notes to Consolidated Financial Statements.

Gas

Information relating to the Company’s gas properties is contained in Item 1 — GAS OPERATIONS AND GAS SUPPLY and Note 3 of Notes to Consolidated Financial Statements.

Substantially all property and plant of the Company is subject to the lien of the Mortgage securing the Company’s First Mortgage Bonds.

Item 3 — Legal Proceedings

Information relating to legal proceedings involving the Company is contained in Item 1 — BUSINESS, THE COMPANY, COMPETITION, ELECTRIC OPERATIONS AND FUEL SUPPLY, RATE REGULATION AND GOVERNMENT LEGISLATION, ENVIRONMENTAL CONSIDERATIONS and Item 8 — Note 4 of Notes to Consolidated Financial Statements.

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

None.

PART II

Item 5 — Market for Registrant’s Common Equity and Related Stockholder Matters

The Company’s common stock is held solely by DPL Inc. and as a result is not listed for trading on any stock exchange.

The information required by this item of Form 10-K is set forth in Item 8 — Selected Quarterly Information and the Financial and Statistical Summary.

As long as any Preferred Stock is outstanding, the Company’s Amended Articles of Incorporation contain provisions restricting the payment of cash dividends on any of its Common Stock if, after giving effect to such dividend, the aggregate of all such dividends distributed subsequent to December 31, 1946 exceeds the net income of the Company available for dividends on its Common Stock subsequent to December 31, 1946, plus $1,200,000. As of year-end, all earnings reinvested in the business of the Company were available for Common Stock dividends.

Item 6 — Selected Financial Data

The information required by this item of Form 10-K is set forth in Item 8 — Financial and Statistical Summary.

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

Overview

The Dayton Power and Light Company (“DP&L” or “the Company”) reported earnings on common stock of $242.6 million, an increase of 3% over earnings on common stock of $234.4 million in 2001. The earnings improvement was primarily attributable to higher retail residential and commercial revenues, and lower fuel and purchased power costs, partially offset by lower wholesale revenues.

Results for 2001 included $6.0 million after tax, reflecting the adoption of the new accounting standard for derivatives in the first quarter, and charges associated with a voluntary early retirement program completed in June 2001 and a non-union workforce reduction program completed in November 2001.

Several events affected the Company’s results in 2000 as it prepared for the deregulation of the energy markets. In the first quarter, the Company expensed $4.2 million before tax benefits to realign its compensation programs more fully with shareholders’ interest. In the third quarter, the Company received an order from the Public Utilities Commission of Ohio (“PUCO”) approving its deregulation transition plan (“Transition Plan”), which resulted in an extraordinary charge of $63.7 million before tax benefits for the elimination of regulatory accounting for the generation business. In the fourth quarter, the Company completed the sale of its natural gas retail distribution operations and reported a pre-tax gain on the sale of $182.5 million. Each of these events affected 2000 financial results as outlined below:

$ in millions	2002		2001			2000

Earnings on Common Stock	$	242.6	$	234.4		$	297.9
Voluntary early retirement		—		3.2			—
Non-union reduction		—		3.8			—
Accounting change		—		(1.0	)		—
Compensation program		—		—			2.7
Deregulation order		—		—			41.4
Gas operations - gain on sale		—		—			(121.0	)

Earnings on Common Stock before unusual and extraordinary items	$	242.6	$	240.4		$	221.0

Income Statement Highlights

$ in millions	2002		2001		2000

Electric:
Revenues	$	1,175.8	$	1,188.2	$	1,110.1
Fuel		208.6		220.1		201.9
Purchased power		106.9		129.8		84.2

Net revenues		860.3		838.3		824.0

Gas Utility: (a)
Revenues		—		—		183.8
Gas purchased for resale		—		—		116.9

Net revenues		—		—		66.9

(a)

The Company completed the sale of its natural gas retail distribution assets and certain liabilities in October 2000.

The increase in net electric revenues in 2002 compared to 2001 was primarily the result of higher retail residential and commercial revenues of $37.6 million or 5% resulting primarily from warmer than normal summer weather in the current year. The increase in retail revenues was partially offset by decreased wholesale revenues of $47.1 million or 24% primarily as a result of lower wholesale electric commodity prices. Cooling degree days were 1,272 for the current year compared to 900 in the prior year. Fuel costs decreased $11.5 million or 6% in 2002 compared to 2001 as a result of the higher availability in 2002 of coal plants that use lower-cost fuel. Purchased power costs decreased $22.9 million or 21% as a result of lower purchased power volumes. In 2001, net electric revenues increased $14.3 million or 2% over 2000 levels primarily as a result of additional peaking generation capacity sales and increased wholesale revenues. Wholesale revenues from existing generation increased as a result of higher sales volume and commodity prices. Growth in residential and commercial sales of 2% was offset by declines in industrial sales of 6%, reflecting economic conditions and mild weather, which reduced overall retail sales by 1%. Fuel costs for existing generation increased from 2000 levels as a result of higher spot-market prices for coal, and greater fuel usage and power purchases resulting from increased wholesale sales.

The decline in net gas revenues resulted from the sale of the natural gas retail distribution assets and certain liabilities, which was completed in October 2000.

Operation and maintenance expense decreased $12.7 million or 8% in 2002 compared to 2001 primarily as a result of lower planned outage costs, lower ash disposal costs, and cost containment efforts. Operation and maintenance expense decreased $26.8 million or 14% in 2001 compared to 2000 primarily as a result of the sale of the natural gas retail distribution operations, lower employee benefit and insurance costs, and general cost containment efforts. These decreases were partially offset by charges for a voluntary early retirement program and a non-union workforce reduction program, totaling $10.7 million before tax benefits. Year to year variances in power plant maintenance costs result from the timing and extent of planned maintenance outages and coal ash removal activities, which can increase or decrease annual maintenance costs by as much as $10 million. Year to year variances in insurance and claims costs result primarily from adjustments to actuarially-determined reserve requirements for risks insured through a captive insurance company wholly-owned by DPL Inc. (“DPL”).

Depreciation and amortization expense decreased $14.3 million or 11% in 2001 compared to 2000 primarily as a result of depreciation rate changes for certain generation units in 2001 and the sale of the natural gas retail distribution assets.

Beginning January 1, 2001, regulatory transition cost assets of $144.8 million are being amortized over a three-year period based on transition revenues. As a result, amortization expense increased by $30.6 million in 2001 for transition revenues recognized during the year.

General taxes increased $10.7 million or 11% in 2002 compared to 2001 primarily as a result of the impact of the Ohio kWh excise tax that was first implemented in May 2001 and higher property taxes, partially offset by the elimination of the Ohio Public Utility Excise Tax at the end of 2001. General taxes decreased $29.7 million or 23% in 2001 compared to 2000 primarily as a result of changes in tax laws associated with the Transition Plan and the sale of the natural gas retail distribution assets.

Other income (deductions) decreased $14.5 million or 58%in 2002 compared to 2001 primarily as a result of income of $7.3 million recognized in the current year for the business interruption insurance policy related to deregulation (see Issues and Financial Risks — Other Matters), as compared to income of $29.0 million recognized for such policy in the prior year. This decrease was partially offset by decreased strategic consulting fees of $4.5 million and a $3.6 million decrease in benefit costs. Other income (deductions) decreased $145.9 million or 85% in 2001 compared to 2000 as a result of the pre-tax $182.5 million gain that was recognized in 2000 for the sale of the natural gas retail distribution operations, partially offset by the 2001 recognition of a receivable for insurance claims as previously discussed, and costs associated with certain compensation programs in 2000.

Interest expense decreased 13% in 2002 compared to 2001 and14% in 2001 compared to 2000 primarily as a result of higher capitalized interest and lower short-term debt levels.

Pursuant to deregulation legislation enacted in Ohio and the Order issued in September 2000 by the PUCO, the Company discontinued the use of its regulatory accounting model for its generation operations. As a result, a $63.7 million before tax benefits ($41.4 million net of taxes) reduction of generation-related regulatory assets was recorded in the third quarter of 2000 as an extraordinary item in accordance with the Financial Accounting Standard Board’s (“FASB”) Statement of Financial Accounting Standards No. 101, “Regulated Enterprises-Accounting for the Discontinuation of Application of FASB Statement No. 71.” (See Note 4 to the Consolidated Financial Statements.)

The cumulative effect of an accounting change reflects the Company’s adoption of FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS No. 133”). SFAS No. 133 requires that all derivatives be recognized as either assets or liabilities in the consolidated balance sheet and be measured at fair value, and changes in the fair value be recorded in earnings, unless they are designated as hedges of an underlying transaction.

Construction Program and Financing

Construction additions are expected to approximate $109 million in 2003, and were $129 million in 2002 and $164 million in 2001. The capital program includes environmental compliance, which is expected to approximate $39 million in 2003, and was $69 and $58 million in 2002 and 2001, respectively.

The Company’s scheduled maturities of long-term debt, including capital lease obligations, over the next three years are $1.1 million each year. The Company expects to finance its construction program and debt maturities in 2003 and 2004 with internal funds.

During 2001, investing cash flows included a cash payment of $90.9 million for income taxes associated with the tax gain on the sale of the natural gas retail distribution operations that occurred in October 2000.

DPL and the Company have $50.0 and $105.0 million, respectively, available through 364 day revolving credit agreements with a consortium of banks. These facilities provide an appropriate amount of credit support for the Company’s business requirements over the next year. Facility fees are approximately $0.2 million per year. The primary purpose of the revolving credit facilities is to provide back-up liquidity for DPL’s and the Company’s commercial paper programs. DPL and the Company had no outstanding borrowings under these credit agreements at December 31, 2002 and 2001.

The Company has $65.0 million available in short-term informal lines of credit. The commitment fees are not material. The Company had no outstanding borrowings under these informal lines and no outstanding commercial paper balances at December 31, 2002 and 2001.

Issuance of additional amounts of first mortgage bonds by the Company is limited by provisions of its mortgage. The amounts and timing of future financings will depend upon market and other conditions, rate increases, levels of sales and construction plans. The Company currently has sufficient capacity to issue first mortgage bonds to satisfy its requirements in connection with the financing of its construction and refinancing programs during the five-year period 2003-2007.

At year-end 2002, the Company’s senior secured debt credit ratings were as follows:


Standard & Poor’s Corp.		BBB
Moody’s Investors Service		A2
Fitch		A

These ratings, which were received in the third quarter of 2002 as a result of annual credit reviews, are lower than prior ratings and remain investment grade. The rating agencies cited pressure from reduced wholesale energy prices and concerns regarding the impact of the global economic downturn on the liquidity of DPL’s financial asset portfolio as the reason for their actions.

Market Risk

The Company’s financial results are impacted by changes in electricity, coal, and gas commodity prices as well as the impact on retail sales volume of weather and economic conditions in the sales area. Six percent of the Company’s 2002 revenues were from spot energy sales in the wholesale market contributing $19 million in net electric revenues. This compares to net electric revenues from spot wholesale energy of $26 million in 2001. This decrease in net wholesale electric revenues resulted primarily from lower wholesale electricity prices in 2002. Spot wholesale energy sales in 2002 and 2001 averaged $22.14 and $29.22 per megawatt hour, respectively. Retail electric sales in 2002 were favorably impacted by above normal weather. Across the year, heating and cooling degree days were 3% above normal, adding approximately $32 million in revenue. This favorable weather impact was partially offset by sluggish demand from industrial customers due to current economic conditions. Fuel and purchased power costs represented 43% of total operating costs in 2002. The Company has contracted for approximately 95% of its coal needs for 2003. Purchased power costs depend upon the timing and extent of planned and unplanned outages of the Company’s generating capacity. The Company has not contracted for its planned purchased power needs for 2003 at this time. A 2% change in overall fuel and purchased power costs would result in a $3.5 million change in net income.

The carrying value of the Company’s debt was $667.0 million at December 31, 2002, consisting of the Company’s first mortgage bonds and guaranteed air quality development obligations. The fair value of this debt was $690.2 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table presents the principal cash repayments and related weighted average interest rates by maturity date for long-term, fixed-rate debt at December 31, 2002.

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

2003	$	1.1		7.4%
2004		1.1		7.4%
2005		1.1		7.4%
2006		1.1		7.4%
2007		9.3		6.5%
Thereafter		653.3		7.5%

Total	$	667.0		7.5%

Fair Value	$	690.2

Because the long-term debt is at a fixed rate, the primary market risk to the Company would be short-term interest rate risk. At December 31, 2002, the Company had no short-term debt outstanding, and therefore, no exposure to short-term interest rate risk.

Critical Accounting Policies

The accounting policies described below are viewed by management as critical because their application is the most relevant and material to the Company’s results of operations and financial position and these policies require the use of material judgments and estimates.

Long-lived Assets: The Company accounts for its long-lived assets at depreciated historical cost. A long-lived asset (asset group) is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. The Company would recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows. Management judgement is involved in both deciding if testing for recoverability is necessary and in estimating undiscounted cash flows.

Regulatory Assets: The Company capitalizes 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. See Note 4 to the consolidated financial statements for further discussion of regulatory matters. The Company applied judgment in the use of this principle when it concluded, as of December 31, 2000, that as a result of deregulation $63.7 million of generation related regulatory assets were no longer probable of recovery, and wrote off these assets as an extraordinary charge. These estimates are based on expected usage by customer class over the designated recovery period. At December 31, 2002, $49.3 million of generation related regulatory assets remain on the balance sheet to be recovered over the remaining transition period ending December 31, 2003 unless extended.

Unbilled Revenues: The Company records 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 impact of weather variations on usage patterns. Unbilled revenues recognized at December 31, 2002 totaled $56.9 million.

Pension and post retirement benefits: The Company accounts for its pension and post retirement 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 Post Retirement Benefits Other than Pensions.” These standards require the use of assumptions, such as the long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans. In 2003, the Company lowered its long-term rate of return assumptions by 25 basis points to reflect the impact of recent trends on its long-term view. This reduction will result in an increase in pension costs of $0.7 million.

Also, on December 31, 2002, the Company lowered its assumed discount rate for pension and postretirement benefits by 50 basis points to reflect current interest rate conditions. Changes in the rate of return assumption, the discount rate, and other components used in the determination of pension or post retirement benefit costs are estimated to result in an overall increase of $5.0 million in pension costs in 2003 compared to 2002. Going forward, differences in the actual return on pension plan assets and assumed return or changes in the discount rate will impact the timing of contributions to the pension plan, if any, and the determination of whether or not a minimum liability should be recorded. Because the Company does not provide postretirement healthcare benefits to employees that retired after 1986, the Company’s exposure to changes in healthcare costs is limited. A one percentage point change in the assumed healthcare trend rate would affect postretirement benefit costs by $0.1 million

Issues and Financial Risks

This report contains certain forward-looking statements regarding plans and expectations for the future. Investors are cautioned that actual outcomes and results may vary materially from those projected due to various factors beyond the Company’s control, including abnormal weather, unusual maintenance or repair requirements, changes in fuel costs, increased competition, regulatory changes and decisions, changes in accounting rules, and adverse economic conditions.

Electric Restructuring Legislation

In October 1999, legislation became effective in Ohio that gave electric utility customers a choice of energy providers starting January 1, 2001. Under the legislation, electric generation, aggregation, 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. As required by the legislation, the Company filed its transition plan at the PUCO on December 20, 1999. The Company received PUCO approval of its plan on September 21, 2000.

The transition plan provides for a three-year transition period, which began on January 1, 2001 and ends on December 31, 2003. The plan also provides for a 5% residential rate reduction on the generation component of the rates, which reduced annual revenue by approximately $14 million; rate certainty for the three year period for customers that continue to purchase power from the Company; guaranteed rates for a six-year period for transmission and delivery services; and recovery of transition costs of approximately $600 million. Under the plan, DPL has the organizational and financial flexibility to continue its growth initiatives.

The Federal Energy Regulatory Commission (“FERC”) issued a final rule on December 20, 1999 specifying the minimum characteristics and functions for Regional Transmission Organizations (“RTO”). The rule required that all public utilities that own, operate, or control interstate transmission lines file a proposal to join an RTO by October 15, 2000 or file a description of efforts taken to participate in an RTO, reasons for not participating in an RTO, any obstacles to participation in an RTO, and any plans for further work toward participation. The Company filed with the FERC on October 16, 2000 to join the Alliance RTO. On December 19, 2001, the FERC issued an order rejecting the Alliance RTO as a stand-alone RTO. However, on April 24, 2002, the FERC approved the Alliance RTO companies’ proposal to form an independent transmission company that will operate under the umbrella of an existing RTO. As of December 31, 2002, the Company had invested approximately $8 million in its efforts to join the Alliance RTO. The FERC recognized in its order that substantial losses were incurred to establish the Alliance RTO and that it would consider proposals for rate recovery of prudently incurred costs.

On May 28, 2002, the Company filed a notice with the FERC stating its intention to join the PJM Interconnection, L.L.C. (“PJM”), an organization responsible for the operation and control of the bulk electric power system throughout major portions of five Mid-Atlantic states and the District of Columbia. On July 31, 2002, the FERC granted the Company conditional approval to join PJM. On September 30, 2002, the Company signed an implementation agreement with PJM with the expectation that the Company will be fully integrated into the PJM market by May 1, 2003. On December 11, 2002, the Company executed the PJM West Transmission Owners Agreement and along with the other new PJM companies, jointly submitted the PJM Open Access Transmission Tariff (“OATT”) filing. This filing adopts a transitional rate design that will maintain revenue neutrality and mitigate cost shifts while eliminating all seams within the new expanded PJM.

On July 22, 1998, the PUCO approved the implementation of Minimum Electric Service and Safety Standards for all of Ohio’s investor-owned electric utilities. This order details minimum standards of performance for a variety of service-related functions, effective July 1, 1999. On December 21, 1999, the PUCO issued additional rules proposed by the PUCO staff, which were designed to guide the electric utility companies as they prepare to enter into deregulation. These rules include certification of providers of competitive retail electric services, minimum competitive retail electric service standards, monitoring the electric utility market, and establishing procedures for alternative dispute resolution. There were also rules issued to amend existing rules for noncompetitive electric service and safety standards and electric companies long-term forecast reporting. The Company submitted comments on the proposed rules on January 31, 2000. The rules were finalized by the PUCO in June 2000 and did not have a material impact on the Company’s financial position.

On October 10, 2002, the PUCO initiated a proceeding to review the financial condition of major public utilities in Ohio. The purpose of this review is to ensure that any adverse financial consequences of parent or affiliated companies unregulated operations do not impact the financial integrity of the regulated public utility. The PUCO is not requesting any financial information from the utilities at this time. The Company filed comments on November 11, 2002, and reply comments on November 22, 2002. The impact of this review cannot be determined at this time.

Sale of Gas Operations

In October 2000, the Company completed the sale of its natural gas retail distribution assets and certain liabilities for $468 million in cash. The transaction resulted in a pre-tax gain of $183 million ($121 million net of tax), which is reflected in “Other income (deductions)” on the Consolidated Statement of Results of Operations. Proceeds from the sale were used to finance DPL’s regional generation expansion and reduce outstanding short-term debt.

Environmental

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 CAA. Generation units operated by partners CG&E (Beckjord 6) and CSP (Conesville 4) and co-owned by the Company were referenced in these actions. Numerous northeast states have filed complaints or have indicated that they will be joining the USEPA’s action against the partners. The Company was not identified in the NOVs, civil complaints or state actions. In December 2000, CG&E announced that it had reached an Agreement in Principle with the USEPA and other plaintiffs in an effort to settle the claims. Discussions on the final terms of the settlement are ongoing. Therefore, it is not possible to determine the outcome of these claims or the impact, if any, on the Company. In June 2000, the USEPA issued a NOV to DP&L-operated J.M. Stuart Station (co-owned by the Company, CG&E, and CSP) for alleged violations of the CAA. The NOV contained allegations consistent with NOVs and complaints that the USEPA had recently brought against numerous other coal-fired utilities in the Midwest. The Company will vigorously challenge the NOV. At this time, it is not possible to determine the outcome of these claims or the impact, if any, on the Company.

In September 1998, the USEPA issued a final rule requiring states to modify their State Implementation Plans (“SIPs”) under the CAA. The modified SIPs are likely to result in further nitrogen oxide (“NOx”) reduction requirements placed on coal-fired generating units by 2004. In order to meet these NOx requirements, the Company’s capital expenditures are estimated to total approximately $175 million, of which $136 million has been spent to-date. Industry groups and others appealed the rules in United States District Court. The requirement for states to submit revised implementation plans has been stayed until the outcome of the litigation. In March 2000, the United States District Court upheld the rule. Industry groups and others have appealed this decision. As a result of the litigation, the Court extended the compliance date of the rule an additional year, until May 31, 2004. In March 2001, the United States Supreme Court refused to hear further appeals of the SIP rules. In December 1999, the USEPA issued final rules granting various CAA Section 126 petitions filed by northeast states. The Company’s facilities were identified, among many others, in the rulemaking. In January 2002, the USEPA announced that reductions required under the CAA Section 126 rulemaking will be extended until May 31, 2004 to be consistent with the NOx SIP rule. The Company’s current NOx reduction strategy and associated expenditures to meet the SIP call should satisfy the rulemaking reduction requirements.

On July 18, 2002, the Ohio Environmental Protection Agency (“Ohio EPA”) adopted rules that will constitute Ohio’s SIP for NOx reductions. The state rules are substantially similar to the reductions required under the federal CAA Section 126 rulemaking and federal NOx SIP rule. The USEPA has conditionally approved Ohio’s NOx SIP. The Company’s current NOx reduction strategy and associated expenditures to meet the federal reduction requirements should satisfy the state SIP reduction requirements.

On December 14, 2000, the USEPA issued a determination that coal- and oil-fired electric generating units should be regulated for emissions of mercury and hazardous air pollutants. The USEPA will issue proposed rules by December 2003 and final rules by December 2004. The impact of the regulatory determination cannot be determined at this time.

In April 2002, the USEPA issued proposed rules governing existing facilities that have cooling water intake structures. Final rules are anticipated in August 2003. The impact of the final rules cannot be determined at this time.

On July 29, 2002, the Bush Administration offered proposed legislation known as the “Clear Skies” initiative. The proposal calls for emissions reductions for sulfur dioxide, nitrogen oxides, and mercury commencing between 2008 and 2010. Senator Jeffords also offered a competing multi-pollutant proposal calling for reductions in sulfur dioxide, nitrogen oxides, mercury, and carbon dioxide emissions with earlier implementation dates. Neither proposal was passed in 2002. The impact of the potential legislation, if passed, cannot be determined at this time.

The Company and numerous other parties have been notified by the USEPA or the Ohio EPA that it considers them Potentially Responsible Parties (“PRP’s”) for clean-up at three superfund sites in Ohio: the North Sanitary (a.k.a. Valleycrest) Landfill in Dayton, Montgomery County, Ohio; the Tremont City Landfill in Springfield, Ohio; and the South Dayton Dump landfill site in Dayton, Ohio.

The Company and numerous other parties received notification from the Ohio EPA on July 27, 1994 that it considers them PRP’s for clean-up of hazardous substances at the North Sanitary Landfill site in Dayton, Ohio. The Company has not joined the PRP group formed for the site because the available information does not demonstrate that the Company contributed hazardous substances to the site. The Ohio EPA has not provided an estimated cost for this site. In October 2000, the PRP group brought an action against the Company and numerous other parties alleging that the Company and the others are PRP’s that should be liable for a portion of clean-up costs at the site. While the Company does not believe it disposed of any hazardous waste at this site, it has entered into an Agreement in Principle with the PRP group to settle any alleged liability for an immaterial amount. The final resolution is not expected to have a material effect on the Company’s financial position, earnings, or cash flow. The Company and numerous other parties received notification from the USEPA in January 2002 for the Tremont City site. The available information does not demonstrate that the Company contributed any hazardous substances to the site. The Company will vigorously challenge this action. The final resolution is not expected to have a material effect on the Company’s financial position, earnings, or cash flow.

The Company and numerous other parties received notification from the USEPA in January 2002 for the Tremont City site. The available information does not demonstrate that the Company contributed any hazardous substances to the site. The Company will virgorously challenge this action. The final resolution is not expected to have a material effect on the Company’s financial position, earnings, or cash flow.

Other Matters

A wholly-owned captive subsidiary of DPL provides insurance coverage solely to DPL including, among other coverages, business interruption and specific risk coverage with respect to environmental law and electric deregulation. “Insurance Claims and Costs” on DPL’s Consolidated Balance Sheet as of December 31, 2002 and 2001 includes insurance reserves of approximately $76 and $87 million, respectively, for this coverage based on actuarial methods and loss experience data. Such reserves are determined, in the aggregate, based on a reasonable estimation of probable insured events occurring. There is uncertainty associated with the loss estimates, and actual results could differ from the estimates. Modification of these loss estimates based on experience and changed circumstances are reflected in the period in which the estimate is reevaluated. As the outcome of electric deregulation becomes known during the three-year regulatory transition period ending December 31, 2003, policy payments from the captive subsidiary to DP&L, receivables for insurance claims for DP&L, or the release of the appropriate reserves will occur and be reflected in income. As of December 31, 2002, a $36 million receivable has been recognized by DP&L for insurance claims under its business interruption policy. Of this amount, $7.3 and $29.0 million was reported as other income in 2002 and 2001, respectively.

In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) which is effective for the Company as of January 1, 2003. SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. The Company’s legal asset retirement obligations are composed of river structures and ash disposal facilities. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Application of the new rules is estimated to result in an increase in net property, plant and equipment of approximately $1 million and recognition of an asset retirement obligation of approximately $4 million. SFAS No. 143 also requires that components of previously recorded depreciation accruals that relate 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. It is estimated that this elimination of cost of removal will reduce the accumulated depreciation reserve in the range of $30 – $35 million. The total cumulative effect of adoption of SFAS 143 will increase net income and shareholder’s equity by approximately $27 – $32 million. Beginning in January 2003, depreciation rates will be reduced to reflect the discontinuation of the cost of removal accrual for applicable non-regulated assets. The estimated impact is an increase of pre-tax income of $2 million. In addition, costs incurred for the removal of retired assets will be charged to operation and maintenance expense rather than to the accumulated depreciation reserve. The impact of this change will vary based on the extent of generating property removal activity.

Beginning January 1, 2003, the Company has changed its accounting for stock options to the fair value method set forth in Statement of Financial Accounting Standard No. 123, “Accounting for Stock-Based Compensation (“SFAS No. 123”).” This standard requires the recognition of compensation expense for stock based awards to be based on the fair value on the date of grant rather than the intrinsic value as was used by the Company prior to January 1, 2003. The Company will adopt SFAS No. 123 on a prospective basis for all grants issued after January 1, 2003. The effect of this new standard will depend on the timing, amount and terms of future stock option awards, if any.

Item 7A — Quantitative and Qualitative Disclosures about Market Risk

Information relating to Market Risk is contained in Item 7 — Management’s Discussion and Analysis.

Item 8 — Financial Statements and Supplementary Data


Index to Consolidated Financial Statements		Page No.

Consolidated Statement of Results of Operations for the three years in the period ended December 31, 2002		34

Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2002		35

Consolidated Balance Sheet as of December 31, 2002 and 2001		36-37


Consolidated Statement of Shareholder’s Equity for the three years in the period ended December 31, 2002		38

Notes to Consolidated Financial Statements		39-54

Report of Independent Accountants		57

Index to Supplemental Information		Page No.

Selected Quarterly Information		55

Financial and Statistical Summary		56

Index to Financial Statement Schedule

Schedule II — Valuation and qualifying accounts		76

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.

The Dayton Power and Light Company

CONSOLIDATED STATEMENT OF RESULTS OF OPERATIONS


	For the years ended December 31,
$ in millions	2002			2001			2000

Revenues
Electric	$	1,175.8		$	1,188.2		$	1,110.1
Gas (Note 3)		—			—			183.8

Total revenues		1,175.8			1,188.2			1,293.9


Expenses
Fuel		208.6			220.1			201.9
Purchased power		106.9			129.8			84.2
Gas purchased for resale (Note 3)		—			—			116.9
Operation and maintenance		151.6			164.3			191.1
Depreciation and amortization		114.9			116.0			130.3
Amortization of regulatory assets, net (Note 4)		48.1			46.9			16.3
General taxes		109.4			98.7			128.4

Total expenses		739.5			775.8			869.1


Operating Income		436.3			412.4			424.8

Other income (deductions) (Note 3)		10.3			24.8			170.7
Interest expense		(53.5	)		(61.5	)		(72.7	)


Income before income taxes, extraordinary item, and Cumulative Effect of Accounting Change		393.1			375.7			522.8

Income taxes		149.6			141.4			182.6


Income Before Extraordinary Item and Cumulative Effect of Accounting Change		243.5			234.3			340.2

Extraordinary item, net of tax		—			—			41.4
Cumulative effect of accounting change, net of tax		—			1.0			—


Net Income		243.5			235.3			298.8

Preferred dividends		0.9			0.9			0.9


Earnings on Common Stock	$	242.6		$	234.4		$	297.9

See Notes to Consolidated Financial Statements.

The Dayton Power and Light Company

CONSOLIDATED STATEMENT OF CASH FLOWS


	For the years ended December 31,
$ in millions	2002			2001			2000

Operating Activities
Net income	$	243.5		$	235.3		$	298.8
Adjustments:
Depreciation and amortization		114.9			116.0			130.3
Amortization of regulatory assets, net		48.1			46.9			16.3
Deferred income taxes		(14.8	)		(6.9	)		(60.5
Gain on sale of natural gas retail distribution operations		—			—			(182.5	)
Noncash extraordinary item, net of tax		—			—			41.4
Changes in working capital:
Accounts receivable		(3.1	)		30.5			(4.6	)
Accounts payable		(10.9	)		10.8			(43.7	)
Net intercompany receivables from parent		—			(6.3	)		6.2
Accrued taxes payable		(6.1	)		(24.5	)		63.5
Inventories		7.2			(15.7	)		(5.8	)
Other		(18.0	)		(52.5	)		26.0

Net cash provided by operating activities		360.8			333.6			285.4


Investing Activities
Capital expenditures		(138.8	)		(161.5	)		(109.9	)
Proceeds from sale of natural gas retail distribution operations, net (Note 3)		—			(90.9	)		468.2

Net cash provided by (used for) investing activities		(138.8	)		(252.4	)		358.3


Financing Activities
Dividends paid on common stock		(204.5	)		(82.4	)		(606.4	)
Retirement of short-term debt, net		—			—			(123.0	)
Retirement of long-term debt		(0.4	)		(0.4	)		(0.4	)
Dividends paid on preferred stock		(0.9	)		(0.9	)		(0.9	)

Net cash used for financing activities		(205.8	)		(83.7	)		(730.7	)


Cash and temporary cash investments—
Net change		16.2			(2.5	)		(87.0	)
Balance at beginning of period		0.9			3.4			90.4

Balance at end of period	$	17.1		$	0.9		$	3.4

Cash paid during the period for:
Interest	$	49.4		$	57.4		$	69.2
Income taxes	$	180.2		$	224.8		$	152.6

See Notes to Consolidated Financial Statements.

The Dayton Power and Light Company

CONSOLIDATED BALANCE SHEETS


	At December 31,
$ in millions	2002			2001

Assets

Property
Property	$	3,781.7		$	3,666.2
Accumulated depreciation and amortization		(1,765.1	)		(1,670.0	)


Net property		2,016.6			1,996.2


Current Assets
Cash and temporary cash investments		17.1			0.9
Accounts receivable, less provision for uncollectible accounts of $10.9 and $12.4 respectively		159.4			156.3
Inventories, at average cost		54.1			61.3
Prepaid taxes		46.9			54.8
Other		65.2			25.5


Total current assets		342.7			298.8


Other Assets
Income taxes recoverable through future revenues		34.6			39.2
Other regulatory assets		71.1			117.9
Trust assets		115.6			141.1
Other assets		79.0			104.9


Total other assets		300.3			403.1


Total Assets	$	2,659.6		$	2,698.1

See Notes to Consolidated Financial Statements.

The Dayton Power and Light Company

CONSOLIDATED BALANCE SHEETS
(continued)


	At December 31,
$ in millions	2002		2001

Capitalization and Liabilities

Capitalization
Common shareholder’s equity
Common stock	$	0.4	$	0.4
Other paid-in capital		771.7		771.6
Accumulated other comprehensive income		1.5		15.6
Earnings reinvested in the business		395.3		357.3


Total common shareholder’s equity		1,168.9		1,144.9

Preferred stock		22.9		22.9
Long-term debt		665.5		666.6


Total capitalization		1,857.3		1,834.4


Current Liabilities
Accounts payable		96.5		110.5
Accrued taxes		100.5		105.6
Accrued interest		19.0		19.0
Other		18.9		21.8


Total current liabilities		234.9		256.9


Deferred Credits And Other
Deferred taxes		370.9		397.0
Unamortized investment tax credit		55.1		58.0
Trust obligations		101.2		102.7
Other		40.2		49.1


Total deferred credits and other		567.4		606.8


Total Capitalization and Liabilities	$	2,659.6	$	2,698.1

See Notes to Consolidated Financial Statements.

The Dayton Power and Light Company

CONSOLIDATED STATEMENT OF SHAREHOLDER’S EQUITY

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

2000:
Beginning balance		41,172,173		$0.4		$769.7		$13.6			$513.9			$1,297.6
Comprehensive income:
Net income											298.8
Unrealized gains, net of reclassification adjustments, after tax (b)								23.7
Total comprehensive income														322.5
Common stock dividends											(606.4	)		(606.4	)
Preferred stock dividends											(0.9	)		(0.9	)
Other						0.1								0.1


Ending balance		41,172,173		0.4		769.8		37.3			205.4			1,012.9

2001:
Comprehensive income:
Net income											235.3
Unrealized losses, net of reclassification adjustments, after tax (b)								(21.6	)
Total comprehensive income														213.7
Common stock dividends											(82.4	)		(82.4	)
Preferred stock dividends											(0.9	)		(0.9	)
Parent company capital contribution						1.7								1.7
Other						0.1		(0.1	)		(0.1	)		(0.1	)


Ending balance		41,172,173		0.4		771.6		15.6			357.3			1,144.9

2002:
Comprehensive income:
Net income											243.5
Unrealized losses, net of reclassification adjustments, after tax (b)								(14.1	)
Total comprehensive income														229.4
Common stock dividends											(204.5	)		(204.5	)
Preferred stock dividends											(0.9	)		(0.9	)
Parent company capital contribution
Other						0.1					(0.1	)		—


Ending balance		41,172,173		$0.4		$771.7		$ 1.5			$395.3			$1,168.9

(a)

50,000,000 shares authorized.

(b)

Net of taxes of $12.8, $(8.0) and $(10.9) million in 2000, 2001 and 2002, respectively.

See Notes to Consolidated Financial Statements.

The Dayton Power and Light Company

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

The Dayton Power and Light Company (“DP&L” or “the Company”) is a wholly-owned subsidiary of DPL Inc. (“DPL”). The accounts of the Company and its wholly-owned subsidiaries are included in the accompanying consolidated financial statements. These statements are presented in accordance with accounting principles generally accepted in the United States, which require management to make estimates and assumptions related to future events. Reclassifications have been made in certain prior years’ amounts to conform to the current reporting presentation. The consolidated financial statements principally reflect the results of operations and financial condition of the Company. DPL and its other wholly-owned subsidiaries provide certain administrative services to the Company. These costs were $5.4 million in 2002, $5.7 million in 2001, and $6.1 million in 2000. The primary service provided by the subsidiaries is insurance. The cost of service is either specifically identified with the Company or allocated based upon the relationships of payroll, revenue and/or property. Management considers the cost of service as reasonable and what would have been incurred on a stand-alone basis.

Revenues and Fuel

For periods prior to January 1, 2001, revenues include amounts charged to customers through fuel and gas recovery clauses, which were adjusted periodically for changes in such costs. Related costs that were recoverable or refundable in future periods were deferred along with the related income tax effects. As of February 2000, the Company’s Electric Fuel Component (“EFC”) was fixed at 1.30¢ per kilowatt-hour through the end of the year and the deferral of over/under-recovered fuel costs was no longer permitted. All remaining deferred fuel balances were amortized to expense in 2000. All gas deferred amounts were included in the sale of the natural gas retail distribution operations (see Note 3). Beginning January 1, 2001, the EFC rate of 1.30¢ became part of the base generation rate. Also included in revenues are amounts charged to customers through a surcharge for recovery of arrearages from certain eligible low-income households.

The Company records revenue for services provided but not yet billed to more closely match revenues with expenses. Accounts receivable on the Consolidated Balance Sheet includes unbilled revenue of $56.9 million in 2002 and $55.4 million in 2001.

Property, Maintenance and Depreciation

Property is shown at its original cost. Cost includes direct labor and material and allocable overhead costs.

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

Depreciation expense is calculated using the straight-line method, which depreciates the cost of property over its estimated useful life, at an average rate of 3.2% for 2002 and 2001, and 3.5% for 2000.

Property is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. The Company would recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows.

The Company capitalizes certain interest costs associated with the construction of property. Capitalized interest totaled $8.7 million, $4.7 million, and $2.4 million in 2002, 2001, and 2000, respectively.

The Company leases office equipment and office space under operating leases with varying terms. Future rental payments under these operating leases at December 31, 2002 are not material.

Repairs and Maintenance

Costs associated with all planned major work and maintenance activities, primarily power plant outages, are recognized at the time the work is performed. These costs are either capitalized or expensed based on Company defined criteria. Outage costs include labor, materials and supplies and outside services required to maintain the Company’s equipment and facilities.

Stock-Based Compensation Cost

The Company followed Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) and related interpretations in accounting for DPL stock options granted to the Company’s employees during the three-year period 2002, 2001, and 2000. If the Company had used a fair-value method of accounting for stock-based compensation cost, earnings on common stock would have been reported as follows:

	Years Ended December 31,
	2002			2001			2000

Earnings on common stock, as reported	$	242.6		$	234.4		$	297.7
Add: Total stock-based employee compensation expense determined under APB 25, net of related tax effects		0.7			1.3			1.3
Deduct: Total stock-based employee compensation expense determined under fair-value based method, net of related tax effects		(2.6	)		(2.9	)		(2.6	)

Proforma earnings on common stock	$	240.7		$	232.8		$	296.4

The Company has elected to apply the provisions of the Financial Accounting Standard Board (“FASB”) Statement of Financial Accounting Standard No. 123, “Accounting for Stock-Based Compensation” on a prospective basis for stock options granted on or after January 1, 2003. The impact of this change in accounting method will depend on the timing and amount of future stock options grants, if any.

Income Taxes

Deferred income taxes are provided for all temporary differences between the financial statement basis and the tax basis of assets and liabilities using the enacted tax rate. For rate-regulated business units, 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. Investment tax credits previously deferred are being amortized over the lives of the related properties.

Consolidated Statement of Cash Flows

The temporary cash investments consist of liquid investments with an original maturity of three months or less.

Financial Derivatives

The Company adopted FASB” Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging activity,” as amended (“SFAS No. 133”) as of January 1, 2001. SFAS No. 133 requires that all derivatives be recognized as either assets or liabilities in the consolidated balance sheet 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. As a result of adopting this accounting standard, the Company recorded a cumulative effect of accounting change of $1.0 million in income net of tax.

The Company uses forward and option purchase contracts 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. The Company also holds forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. Prior to July 1, 2001, the Company recorded the fair value of all these contracts as “Other assets” or “Other liabilities” on the Consolidated Balance Sheet with an offset to “Accumulated other comprehensive income,” which is recognized as earnings in the month of physical receipt or delivery of power. In June 2001, 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. Accordingly, the Company began to apply the normal purchase and sales exception as defined in SFAS No. 133 as of July 1, 2001 and currently accounts for these contracts upon settlement. This change did not have a material impact on the Company’s financial position or results of operations.

The Company also holds emission allowance options through 2004 that are classified as derivatives not subject to hedge accounting. The fair value of these contracts is reflected as “Other assets” or “Other liabilities” on the Consolidated Balance Sheet and changes in fair value are recorded as “Other income (deductions)” on the Consolidated Statement of Results of Operations. The impact on net income was immaterial during 2002 and 2001.

2. Recent Accounting Standard

In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) which is effective for the Company as of January 1, 2003. SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. The Company’s legal asset retirement obligations are composed of river structures and ash disposal facilities. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Application of the new rules is estimated to result in an increase in net property, plant and equipment of approximately $1 million and recognition of an asset retirement obligation of approximately $4 million. SFAS No. 143 also requires that components of previously recorded depreciation accruals that relate 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. It is estimated that this elimination of cost of removal will reduce the accumulated depreciation reserve in the range of $30 — $35 million. The total cumulative effect of adoption of SFAS 143 will increase net income and shareholder’s equity by approximately $27 — $32 million. Beginning in January 2003, depreciation rates will be reduced to reflect the discontinuation of the cost of removal accrual for applicable non-regulated assets. The estimated impact is an increase of pre-tax income of $2 million. In addition, costs incurred for the removal of retired assets will be charged to operation and maintenance expense rather than to the accumulated depreciation reserve. The impact of this change will vary based on the extent of generating property removal activity.

3. Sale of the Gas Business

In October 2000, the Company completed the sale of its natural gas retail distribution assets and certain liabilities for $468 million in cash. The transaction resulted in a pre-tax gain of $183 million ($121 million net of taxes), which is reflected in “Other income (deductions)” on the Consolidated Statement of Results of Operations. Proceeds from the sale were used to finance DPL’s regional generation expansion and reduce outstanding short-term debt.

4. Regulatory Matters

The Company applies the provisions FASB Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”) to its regulated operations. This accounting standard provides for the deferral of costs authorized for future recovery by regulators. Based on existing regulatory authorization, regulatory assets on the Consolidated Balance Sheet include:

	At December 31,
$ in million	2002		2001

Regulatory transition costs (a)	$	49.3	$	97.2
Income taxes recoverable through future revenues (b)		34.6		39.2
Other costs (b)		21.8		20.7

Total	$	105.7	$	157.1

(a) During 1999, legislation was enacted in Ohio, which restructures the state’s electric utility industry (“the Legislation”). Beginning in 2001, electric generation, aggregation, power marketing and power brokerage services applied to Ohio retail customers are not subject to regulation by the Public Utilities Commission of Ohio (“PUCO”). As required by the Legislation, the Company filed its transition plan (“the Plan”) at the PUCO in 1999, which included an application for the Company to receive transition revenues to recover regulatory assets and other potentially stranded costs. Final PUCO approval of the Plan was received in September 2000.

The Plan, which began in January 2001, provides for a three-year transition period (“the Transition Period”) ending December 31, 2003. As a result of the PUCO final approval of the transition plan and tariff schedules, the application of SFAS No. 71 was discontinued for generation-related assets. Transmission and distribution services, which continue to be regulated based on PUCO-approved cost based rates, continue to apply SFAS No. 71. The Plan, as approved, provides for the recovery of a portion of the Company’s transition costs, including generation-related regulatory assets, during the Transition Period. Based on the Company’s assessment of recoveries of regulatory assets during the Transition Period, a $63.7 million before tax benefits ($41.4 million net of taxes) reduction of generation-related regulatory assets was recorded in the third quarter of 2000 as an extraordinary item in accordance with FASB Statement of Accounting Standards No. 101, “Regulated Enterprises-Accounting for the Discontinuation of Application of FASB Statement No. 71” and other generation-related regulatory assets were reclassified to the “Regulatory transition costs” asset.

(b) Certain deferred costs remain authorized for recovery by regulators. These relate primarily to the Company’s electric transmission and distribution operations and are being amortized over the recovery period of the assets involved.

5. Income Taxes

	For the years ended December 31,
$ in millions	2002			2001			2000

Computation of tax expense

Federal income tax (a)	$	149.3		$	139.6		$	183.0

Increases (decreases) in tax from —
Depreciation		2.1			4.5			6.5
Investment tax credit amortized		(2.9	)		(2.3	)		(6.1	)
Other, net		1.1			(0.4	)		(0.8	)


Total tax expense	$	149.6		$	141.4		$	182.6


Components of Tax Expense

Taxes currently payable	$	164.4		$	146.9		$	243.0
Deferred taxes —
Regulatory assets		(16.8	)		(12.5	)		(13.3	)
Liberalized depreciation and amortization		(1.4	)		(5.7	)		(29.3	)
Fuel and gas costs		—			1.1			(7.1	)
Other		6.3			13.9			(4.6	)
Deferred investment tax credit, net		(2.9	)		(2.3	)		(6.1	)


Total tax expense	$	149.6		$	141.4		$	182.6

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

Components of Deferred Tax Assets and Liabilities

	At December 31,
$ in millions	2002			2001

Non-current Liabilities

Depreciation/property basis	$	(391.4	)	$	(392.8	)
Income taxes recoverable		(9.1	)		(14.4	)
Regulatory assets		(23.6	)		(38.6	)
Investment tax credit		19.3			20.7
Other		33.9			28.1


Net non-current liability	$	(370.9	)	$	(397.0	)


Net Current Asset	$	2.6		$	1.3

6. Pensions and Postretirement Benefits

Pensions

Substantially all Company employees participate in pension plans paid for by the Company. Employee benefits are based on their years of service, age, compensation and year of retirement. The plans are funded in amounts actuarially determined to provide for these benefits.

The following tables set forth the plans’ obligations, assets and amounts recorded in “Other assets” on the Consolidated Balance Sheet at December 31:

$ in millions	2002			2001

Change in Projected Benefit Obligation
Benefit obligation, January 1	$	271.2		$	273.7
Service cost		3.7			4.3
Interest cost		19.2			17.3
Amendments		—			0.2
Special termination benefit (a)		—			5.3
Actuarial loss		(8.6	)		(13.4	)
Benefits paid		(18.6	)		(16.2	)

Benefit obligation, December 31		266.9			271.2


Change in Plan Assets
Fair value of plan assets, January 1		281.3			361.3
Actual return on plan assets		5.9			(63.8	)
Benefits paid		(18.6	)		(16.2	)

Fair value of plan assets, December 31		268.6			281.3


Plan assets in excess of projected benefit obligation		1.7			10.1
Unrecognized actuarial loss		61.4			44.1
Unamortized prior service cost		15.7			18.6

Net pension assets	$	78.8		$	72.8

Assumptions used in determining the projected benefit obligation were as follows:

	2002		2001		2000

Discount rate for obligations	6.75	%	7.25	%	7.25	%
Expected return on plan assets	8.75	%	9.00	%	9.00	%
Average salary increases	4.00	%	4.00	%	5.00	%

The following table sets forth the components of pension expense (portions of which were capitalized):

$ in millions		2002			2001			2000

Expense for Year
Service cost	$	3.7		$	4.3		$	5.1
Interest cost		19.2			17.3			18.9
Expected return on plan assets		(32.2	)		(32.9	)		(33.9	)
Amortization of unrecognized:
Actuarial (gain) loss		0.4			(6.6	)		(5.0	)
Prior service cost		2.9			3.5			4.2
Transition obligation		—			—			(2.8	)

Net pension benefit		(6.0	)		(14.4	)		(13.5	)
Special termination benefit (a)		—			5.3			—
Curtailment (a)		—			1.4			2.1

Net pension benefit after special termination benefit and curtailment	$	(6.0	)	$	(7.7	)	$	(11.	4)

(a)

The special termination benefit was recognized as a result of 63 employees who participated in a voluntary early retirement program and retired as of July 1, 2001.

(b)

The curtailment in 2001 was recognized as a result of a non-union workforce reduction program that was completed in November 2001. The curtailment in 2000 was recognized as a result of the completion of the sale of the natural gas retail distribution assets and certain liabilities in October 2000 (see Note 3).

Postretirement Benefits

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

The following tables set forth the accumulated postretirement benefit obligation (“APBO”), assets and funded status amounts recorded in “Other deferred credits” on the Consolidated Balance Sheet at December 31:

$ in millions	2002			2001

Change in APBO
Benefit obligation, January 1	$	33.0		$	30.8
Interest cost		2.4			2.2
Actuarial loss		3.5			2.6
Benefits paid		(3.2	)		(2.6	)

Benefit obligation, December 31		35.7			33.0

$ in millions	2002			2001

Change in Plan Assets
Fair value of plan assets, January 1		10.9			10.9
Actual return on plan assets		0.8			0.9
Company contributions		2.2			1.8
Benefits paid		(3.2	)		(2.7	)

Fair value of plan assets, December 31		10.7			10.9


APBO in excess of plan assets		25.0			22.1
Unamortized transition obligation		(0.9	)		(3.9	)
Actuarial gain		13.0			17.6

Accrued postretirement benefit liability	$	37.1		$	35.8

Assumptions used in determining the projected benefit obligation were as follows:

	2002		2001		2000

Discount rate for obligations	6.75	%	7.25	%	7.25	%
Expected return on plan assets	6.75	%	7.00	%	7.00	%

The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation was 8.8% and 7.0% for 2002 and 2001, respectively, and decreases to 5.0% by 2007. A one percentage point change in the assumed health care trend rate would affect the service and interest cost by $0.1 million. A one percentage point increase in the assumed health care trend rate would increase the postretirement benefit obligation by $2.0 million; and a one percentage point decrease would decrease the benefit obligation by $1.8 million.

The following table sets forth the components of postretirement benefit expense:

$ in millions		2002			2001			2000

Expense for Year
Interest cost	$	2.4		$	2.2		$	2.2
Expected return on plan assets		(0.7	)		(0.7	)		(0.7	)
Amortization of unrecognized:
Actuarial loss		(1.2	)		(1.6	)		(2.2	)
Transition obligation		2.9			2.9			2.9

Postretirement benefit cost		3.4			2.8			2.2
Curtailment (a)		—			—			0.1

Postretirement benefit cost after curtailment	$	3.4		$	2.8		$	2.3

(a)

The curtailment was recognized as a result of the completion of the sale of the natural gas retail distribution assets and certain liabilities in October 2000 (see Note 3).

7. 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.

Series

A	3.75	%	$102.50	93,280	$ 9.3
B	3.75	%	$103.00	69,398	7.0
C	3.90	%	$101.00	65,830	6.6


Total				228,508	$22.9

The shares may be redeemed at the option of the Company at the per share prices indicated, plus cumulative accrued dividends. In August 2000, the Company announced that it would redeem the outstanding shares in conjunction with its corporate separation plan required by the Ohio deregulation legislation. Current market conditions and regulatory requirements regarding legal separation of the electric operations do not justify a redemption at this time. Over the remainder of the deregulation transition period, the Company will continue to evaluate whether redemption of the preferred stock is warranted.

8. Long-term Debt

	At December 31,
$ in millions	2002			2001

First mortgage bonds maturing 2024-2026 8.01% (a)	$	446.0		$	446.0
Pollution control series maturing through 2027 6.43% (a)		105.2			105.6

		551.2			551.6

Guarantee of Air Quality Development Obligations
6.10% Series Due 2030		110.0			110.0
Obligation for capital lease		4.7			5.4
Unamortized debt discount and premium (net)		(0.4	)		(0.4	)

Total	$	665.5		$	666.6

(a) Weighted average interest rate for 2002 and 2001.

The amounts of maturities and mandatory redemptions for first mortgage bonds, notes, and the capital lease are $1.1 million per year in 2003 through 2007. Substantially all property of the Company is subject to the mortgage lien securing the first mortgage bonds.

9. Notes Payable and Compensating Balances

DPL and the Company have $50.0 and $105.0 million, respectively, available through revolving credit agreements with a consortium of banks. The DPL facility contains three financial covenants including maximum debt to total capitalization, minimum EBIT to interest coverage and minimum tangible net worth. The Company’s facility contains two financial covenants including maximum debt to total capitalization, and minimum EBIT to interest coverage. Each of these covenants is currently met. Facility fees are approximately $0.2 million per year. The primary purpose of the revolving credit facilities is to provide back-up liquidity for DPL and the Company’s commercial paper programs. At December 31, 2002 and 2001, DPL and the Company had no outstanding borrowings under these credit agreements.

The Company has $65.0 million available in short-term informal lines of credit. The commitment fees are immaterial. Borrowings at December 31, 2002 and 2001 were zero.

The Company had no outstanding commercial paper balances at December 31, 2002 and 2001.

10. Employee Stock Plans

In 2000, DPL’s Board of Directors adopted and its shareholders approved the DPL Inc. Stock Option Plan. On February 1, 2000, options were granted at an exercise price of $21.00, which was above the market price of $19.06 per share on that date. The exercise price of options granted after that date approximated the market price of the stock on the date of grant. Options granted in 2000 and 2001 represent three-year awards, vest five years from the grant date, and expire ten years from the grant date. Options granted in 2002 vest in three years and expire ten years from the grant date. At December 31, 2002, there were 624,500 options available for grant.

Summarized stock option activity was as follows:

		2002			2001			2000

Options granted at beginning of year		7,232,500			7,610,000			—
Granted		900,000			127,500			7,610,000
Exercised		—			—			—
Forfeited		(773,000	)		(505,000	)		—

Outstanding at year-end		7,359,500			7,232,500			7,610,000
Exercisable at year-end		—			—			—

Weighted average option prices per share:
At beginning of year	$	21.99		$	22.10		$	—
Granted		14.95			27.17			22.10
Exercised		—			—			—
Forfeited		21.80			24.97			—
Outstanding at year-end		20.90			21.99			22.10
Exercisable at year-end	$	—		$	—		$	—

The weighted-average fair value of options granted was $2.56, $3.47, and $3.65 per share in 2002, 2001, and 2000, respectively. The fair values of options were estimated as of the date of grant using a Black-Scholes option pricing model utilizing the following assumptions:

	2002		2001		2000

Volatility	24.0	%	18.5	%	18.5	%
Expected life (years)	8.0		5.1		5.1
Dividend yield rate	4.3	%	3.6	%	3.5	%
Risk-free interest rate	3.4	%	4.5	%	6.8	%

The following table reflects information about stock options outstanding at December 31, 2002:

			Options Outstanding				Options Exercisable
Range of Exercise Prices	Number Outstanding		Weighted- Average Contractual Life in years)		Weighted- Average Exercise Price		Number Exercisable		Weighted- Average Exercise Price

$14.95-$21.00		6,745,000		7.4		$20.19		—		—
$21.01-$29.63		614,500		7.9		$28.72		—		—

11. Ownership of Facilities

The Company 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 allocable 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, 2002, the Company had $142.1 million of construction in progress at such facilities. The Company’s share of the operating cost of such facilities is included in the Consolidated Statement of Results of Operations, and its share of the investment in the facilities is included in the Consolidated Balance Sheet.

The following table presents the Company’s undivided ownership interest in such facilities at December 31, 2002:

	Company Share				Company Investment
	Ownership (%)		Production Capacity (MW)		Gross Plant in Service ($ in millions)

Production Units:
Beckjord Unit 6		50.0		210		$ 60
Conesville Unit 4		16.5		129		31
East Bend Station		31.0		186		178
Killen Station		67.0		418		381
Miami Fort Units 7 & 8		36.0		360		160
Stuart Station		35.0		823		276
Zimmer Station		28.1		365		1,000

Transmission (at varying percentages)						88

12. Fair Value of Financial Instruments

	At December 31,
			2001 Gross Unrealized									2001 Gross Unrealized
$ in millions	Fair Value		Gains		Losses			Cost		Fair Value		Gains		Losses			Cost

Assets
Available-for-sale equity securities	$	65.8	$	50.5	$	(46.5	)	$	61.8	$	95.3	$	43.9	$	(14.4	)	$	65.8

Held-to-maturity securities:
Debt securities (a)		51.4		1.4		—			50.0		45.8		—		(0.2	)		46.0

Total	$	117.2	$	51.9	$	(46.5	)	$	111.8	$	141.1	$	43.9	$	(14.6	)	$	111.8

Liabilities (b)
Debt	$	690.2						$	667.0	$	678.8						$	668.1

(a) Maturities range from 2003 to 2010.
(b) Includes current maturities.

Gross realized gains and (losses) were $0.3 and $(2.8) million in 2002, $0.9 and $(6.2) million in 2001, and $0.1 and $(0.5) million in 2000, respectively.

13. Business Segment Reporting

The Company provides electric services to over 500,000 retail customers in West Central Ohio. The Company also sold and distributed natural gas until October 31, 2000, at which time the Company completed the sale of its natural gas retail distribution assets and certain liabilities (see Note 3).

In prior years, the Company had two reportable operating segments: Electric and Natural Gas. As a result of the sale of the natural gas retail distribution operations, the Electric segment is the remaining reportable operating segment. Assets and related costs associated with the Company’s transmission and distribution and base load and peaking generation operations are managed and evaluated as a single operating segment.

$ in millions		2002			2001			2000

Net revenues:
Electric	$	860.3		$	838.3		$	824.0
Natural Gas		—			—			66.9

Total	$	860.3		$	838.3		$	890.9


Operating income:
Electric	$	444.6		$	415.1		$	407.7
Natural Gas		—			—			24.2
Other (a)		(8.3	)		(2.7	)		(7.1	)

Total operating income		436.3			412.4			424.8
Other income (deductions)		10.3			24.8			170.7
Interest expense		(53.5	)		(61.5	)		(72.7	)

Income before income taxes, extraordinary item, and cumulative effect of accounting change	$	393.1		$	375.7		$	522.8


Depreciation and amortization:
Electric	$	114.9		$	116.0		$	122.9
Natural Gas		—			—			7.4
Total	$	114.9		$	116.0		$	130.3


Expenditures - construction additions:
Electric	$	129.4		$	164.4		$	117.8
Natural Gas		—			—			7.1

Total	$	129.4		$	164.4		$	124.9


Assets
Electric	$	2,507.1		$	2,546.6		$	2,545.7
Natural Gas		—			—			—
Unallocated corporate assets		152.5			174.3			205.4

Total assets	$	2,659.6		$	2,720.9		$	2,751.1

(a) Includes unallocated corporate items.

SELECTED QUARTERLY INFORMATION (Unaudited)

	March 31,				June 30,				September 30,				December 31,
$ in millions		2002		2001		2002		2001		2002		2001		2002		2001

Electric revenues	$	272.2	$	294.7	$	279.1	$	287.2	$	341.7	$	351.5	$	282.8	$	254.8
Operating income		87.3		112.9		104.2		86.8		137.1		142.4		107.7		70.3
Income before income taxes, extraordinary item, and cumulative effect of accounting change		83.6		94.5		88.4		72.3		124.0		136.6		97.1		72.3
Income before extraordinary item and cumulative effect of accounting change		52.6		56.5		55.9		45.5		74.5		85.5		60.5		46.8
Net income		52.6		57.5		55.9		45.5		74.5		85.5		60.5		46.8
Earnings on common stock		52.4		57.3		55.7		45.3		74.2		85.2		60.3		46.6
Cash dividends paid		—		8.1		—		57.3		150.0		17.0		54.5		—

FINANCIAL AND STATISTICAL SUMMARY (Unaudited)

	2002

For the years ended December 31,

Electric revenues (millions)	$	1,175.8	1,188.2	1,110.1	1,058.3	1,073.0
Gas revenues (millions)	$	—	—	183.8	215.0	211.2
Earnings on common stock (millions)	$	242.6	234.4	297.9	191.6	168.6

Cash dividends paid (millions)	$	204.5	82.4	606.4	130.3	238.8

Electric sales (millions of kWh)—
Residential		5,302	4,909	4,816	4,725	4,790
Commercial		3,710	3,618	3,539	3,390	3,518
Industrial		4,472	4,568	4,851	4,876	4,655
Other retail		1,405	1,369	1,371	1,305	1,360

Total retail		14,889	14,464	14,577	14,296	14,323
Wholesale		4,358	3,591	2,946	2,571	3,158

Total		19,247	18,055	17,523	16,867	17,481

Gas sales (thousands of MCF)— (a)
Residential		—	—	18,538	24,450	24,877
Commercial		—	—	5,838	7,647	7,433
Industrial		—	—	2,034	2,246	1,916
Other		—	—	776	1,182	1,699
Transported gas		—	—	16,105	20,190	17,788


Total		—	—	43,291	55,715	53,713

At December 31,

Total assets (millions)	$	2,659.6	2,720.9	2,721.5	3,153.5	3,412.4
Long-term debt (millions)	$	665.5	666.6	666.5	661.2	885.6

First mortgage bond ratings—
Standards & Poor’s Corporation		BBB	BBB+	BBB+	AA-	AA-
Moody’s Investors Service		A2	A2	A2	Aa3	Aa3

Number of Preferred Shareholders		426	476	471	509	559

(a)

The Company completed the sale of its natural gas retail distribution assets and certain liabilities in October 31, 2000.

Report of Independent Accountants

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

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of The Dayton Power and Light Company and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Dayton, Ohio
January 27, 2003

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

None.

PART III

Item 10 — Directors and Executive Officers of the Registrant

Directors of the Registrant

The Board is presently authorized to consist of ten directors and one advisory director. These directors are also directors of DPL Inc., the holding company of the Company.

The following information regarding the directors and nominees is based on information furnished by them:

		Director Since

THOMAS J. DANIS, Age 53		1989
Chairman and Chief Executive Officer, The Danis Companies, Dayton, Ohio, construction, real estate and environmental services.

JAMES F. DICKE, II, Age 57		1990
President, Crown Equipment Corporation, New Bremen, Ohio, international manufacturer and distributor of electric lift trucks and material handling products.
Director: Gulf States Paper Co.
Trustee: Trinity University, Culver Educational Foundation
Commissioner: Smithsonian American Art Museum

PETER H. FORSTER, Age 60		1979
Chairman, DPL Inc. and The Dayton Power and Light Company.
Chairman: Miami Valley Research Foundation.
Director: Amcast Industrial Corp.
Trustee: F. M. Tait Foundation.

ERNIE GREEN, Age 64		1991
President and Chief Executive Officer, Ernie Green Industries, Dayton, Ohio, automotive components manufacturer.
Director: Pitney Bowes Inc., Eaton Corp.

		Director Since

JANE G. HALEY, Age 72		1978
President and Chief Executive Officer, Gosiger, Inc., Dayton, Ohio, national importer and distributor of machine tools.
Director: The Ultra-Met Company, Urbana, Ohio, ONA America, Dayton, Ohio.
Trustee: University of Dayton, Chaminade-Julienne High School, Dayton, Ohio.
Member: Dayton Development Coalition, Area Progress Council.

W AUGUST HILLENBRAND, Age 62		1992
Chief Executive Officer, Hillenbrand Capital Partners, 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.
Director: Hillenbrand Industries, Pella Corporation.
Trustee: Batesville Girl Scouts.
Trustee Emeritus: Denison University.

STEPHEN F. KOZIAR, Age 58		2002
President and Chief Executive Officer, DPL Inc. and The Dayton Power and Light Company.
Board Member: The Miami Valley Council of Boy Scouts of America, Ohio Electric Utility Institute and The Dayton Power and Light Company Foundation.

		Director Since

SCOTT M. STUART, Age 43		2000
Member, KKR & Co. LLC, New York City, investment company.
Director: Borden, Inc., The Boyds Collection, Ltd.

WALLACE CREEK, Age 63 (Nominee)
Senior Vice President, Collins & Aikman Corporation, Detroit, Michigan, cockpit modules and automotive components manufacturers.
Director: Columbus McKinnon Corporation, Quantom Technologies, Inc.

MICHAEL W. GREBE, Age 61 (Nominee)
President and Chief Executive Officer, The Lynde and Harry Bradley Foundation, Milwaukee, Wisconsin, grant-making institution.
Director: Oshkosh Truck Corporation, Milwaukee Brewers Baseball Club.

Advisory Director:

GEORGE R. ROBERTS, Age 59		2000
Partner, Kohlberg Kavis Roberts & Co. L.P. and Managing Member of KKR & Co. LLC, New York City, investment company.
Director: Borden, Inc., The Boyds Collection, Ltd., KinderCare Learning Center, Inc., KSL Recreation Group, Inc., Owens-Illinois, Inc., PRIMEDIA, Inc., Safeway Inc., Willis Group Holdings Limited.
Trustee: Claremont McKenna College, Culver Military Academy.
Member: San Francisco Symphony, San Francisco Ballet, Fine Arts Museum.

Name	Age	Business Experience, Last Five Years (Positions with Registrant Unless Otherwise Indicated)	Dates
Allen M. Hill*	57	President and Chief Executive Officer, DPL Inc. and the Company	1/01/97 - 1/01/03
		President and Chief Executive Officer, the Company	4/06/92 - 1/01/03

Stephen F. Koziar, Jr	58	President and Chief Executive Officer, DPL Inc. and the Company	1/01/03 - 1/01/03
		Executive Vice President and Chief Operating Officer, DPL Inc. and the Company	8/28/02 - 1/01/03
		Group Vice President and Secretary, DPL Inc. and the Company	1/31/95 - 8/28/02

Elizabeth M. McCarthy	43	Group Vice President and Chief Financial Officer, DPL Inc. and the Company	9/26/00 - 1/01/03
		Vice President and Chief Accounting Officer, DPL Inc. and the Company	4/01/00 - 9/26/00
		Partner, PricewaterhouseCoopers LLP, New York, NY	7/01/94 - 3/31/00

Arthur G. Meyer	52	Vice President, Legal and Corporate Affairs and Corporate Secretary, DPL Inc. and the Company	10/4/02 - 1/01/03
		Vice President, Legal and Corporate Affairs, the Company	11/21/97 - 10/4/02

H. Ted Santo*	52	Group Vice President, the Company	12/08/92 - 1/01/03

Patricia K. Swanke	43	Vice President, Operations, the Company	9/29/99 - 1/01/03
		Managing Director, the Company	9/08/96 - 9/29/99

W. Steven Wolff	49	Vice President, Power Production, DPL Inc. and the Company	8/28/02 - 1/01/03
		Director, Power Production, the Company	1/07/02 - 8/28/02
		Manager, Power Plant – OHH – Killen, the Company	8/01/01 - 1/07/02

* Retired effective January 1, 2003

Item 11 — Executive Compensation

COMPENSATION OF DIRECTORS

Directors of the Company who are not employees received an annual award of 1,500 common share units for services as a director. The annual share unit award replaced cash director fees effective July 1, 2000. Previously, directors received $12,000 annually plus meeting attendance and committee fees.

Non-employee directors were eligible to receive grants of stock options under the DPL Inc. Stock Option Plan. Each non-employee director, except Mr. Forster, was granted an option to purchase 50,000 shares on February 1, 2000 at an above market exercise price of $21.00 per share. The closing price on February 1, 2000 was $19.06 per share. These options represent a three-year block grant, are currently exercisable and expire on February 1, 2010.

With the expiration of the Director Stock Option Plan, beginning in 2003, Director Compensation will consist of a Retainer of $55,000, Board Meeting fees of $5,000 per meeting, Committee Chair Retainer of $10,000, Committee Meeting Fees of $4,000 per meeting and a Special Meeting fee of $3,000 per meeting.

DPL Inc. maintains a Deferred Compensation Plan for non-employee directors in which payment of directors’ fees may be deferred. Under the standard deferred income program directors are entitled to receive a lump sum payment or payments in installments over a period up to 20 years. Effective January 31, 2000, the supplementary deferred income program was terminated for current directors and the value of each director’s supplementary account transferred to his or her standard deferral account. All current directors have designated their standard deferral account be invested in DPL Inc. common share units.

Mr. Forster, who retired as Chief Executive Officer of DPL Inc. effective December 31, 1996, entered into a three year agreement with DPL Inc. and the Company pursuant to which he serves as Chairman of the Board of DPL Inc. and the Company and provides advisory and strategic planning services. The term of the agreement is automatically extended each December 31 for an additional year unless either party gives advance notice of nonrenewal. For these services, Mr. Forster receives an annual fee of $650,000 (as well as such bonuses, if any, as may be determined by the Compensation and Management Review Committee in its discretion) and is eligible to receive grants of stock options under the DPL Inc. Stock Option Plan. As Chairman, Mr. Forster is responsible for the long-term strategic planning of the Company, the oversight of financial assets, and the evaluation and recommendations relating to the merger, acquisition and disposition of utility assets. Mr. Forster participates in an incentive program for individuals managing financial assets.

EXECUTIVE OFFICER COMPENSATION

Summary Compensation Table

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

		Annual Compensation				Long Term Compensation
Name and Principal Position	Year	Salary ($)		Bonus (1) ($)		Securities Underlying Options (2) (Number)		LTIP Payouts (3) ($)		All Other Compensation (4) ($)
Allen M. Hill (5)	2002	$	730,000	$	210,000	—			—	$	1,000
President and Chief	2001		675,000		—	—			—		1,000
Executive Officer	2000		600,000		300,000	1,350,000	sh.	$	2,180,000		1,000

Stephen F. Koziar, Jr (6)	2002	$	375,000	$	210,000	300,000	sh.		—	$	1,000
President and Chief	2001		302,000		—	—			—		1,000
Executive Officer, elect	2000		272,000		100,000	495,000	sh.	$	1,100,000		1,000

Peter H. Forster (7)	2002	$	650,000	$	100,000	300,000	sh.	$	840,000	$	39,375
Chairman	2001		600,000		—	—			—		43,000
	2000		550,000		300,000	2,400,000	sh.		3,312,000		61,000

Elizabeth M. McCarthy (8)	2002	$	345,000	$	47,000	—			—	$	1,000
Group Vice President and	2001		330,000		—	125,000	sh.		—		1,000
Chief Financial Officer	2000		280,000		220,000	250,000	sh.	$	300,000		1,000

H. Ted Santo (9)	2002	$	291,000	$	79,000	—			—	$	1,000
	2001		283,000		—	—			—		1,000
	2000		271,000		109,350	375,000	sh.	$	100,000		1,000

(1)

Amounts in this column represent awards made under the Management Incentive Compensation Program (“MICP”). Awards are based on achievement of specific predetermined operating and management goals in the year indicated and paid in the year earned or in the following year.

(2)

Amounts in this column for 2002 represent a three-year block grant of stock options to the named executive under the DPL Inc. Stock Option Plan in lieu of awards under the Management Stock Incentive Plan (“MSIP”). Each executive, except Ms. McCarthy, was granted a number of option shares equal to three times the executive’s earned Restricted Share Units (“RSUs”) held in the Master Trust under the MSIP. See “Option Grants in Last Fiscal Year.”

(3)

Amounts shown for 2000 include the dollar value of a one-time contingent award of RSUs approved by the Compensation Committee in 1999 which could be earned only if the closing price of DPL Inc. common shares on the NYSE Consolidated Transactions Tape achieved $26 per share between June 1999 and July 1, 2001. These RSUs were earned in 2000 and settled in cash.

Amounts in this column also represent annualized incentives earned by the named executive officer under a long-term incentive program for individuals managing all financial assets of DPL Inc. For 2000, incentives were earned based on annual performance and include $100,000 for Mr. Hill, $1.232 million for Mr. Forster and $100,000 for Mr. Koziar. In 2001, no incentives were awarded under this program. In 2002, Mr. Forster was awarded $840,000 based on financial asset performance in 2001.

(4)

Amounts in this column represent employer matching contributions on behalf of each named executive, except Mr. Forster, under the Company Employee Savings Plan made to the DPL Inc. Employee Stock Ownership Plan.

(5)

Mr. Hill retired from the Company effective January 1, 2003 after 33 years of service and from the Board of Directors. We offer our sincere appreciation to Mr. Hill and wish him well in his future endeavors.

(6)

Mr. Koziar has an employment agreement with DPL Inc. which provides for annual base salary of not less than $600,000, participation in the MICP, Stock Option Plan, other incentive programs and fringe benefits for executives. The agreement continues to December 31, 2005 unless earlier terminated as provided in the agreement and provides for salary continuation under certain circumstances.

(7)

Annual compensation shown for Mr. Forster for 1999, 2000 and 2001 was paid pursuant to an agreement with DPL Inc. and the Company. All other compensation shown for 2001 represents the dollar value of the annual award of 1,500 shares to each non-employee director in lieu of directors fees, and for 2000 represents directors fees of $26,700 and the dollar value of the annual award of 1,500 shares to each non-employee director in lieu of directors fees and for 1999 represents directors fees of $37,000 and an award of 2,700 shares under the Directors’ Stock Plan. Participation in the Director compensation program by Mr. Forster was terminated during the year 2000.

(8)

Ms. McCarthy joined DPL Inc. in March 2000. Ms. McCarthy has an employment agreement with DPL Inc. which provides for annual base salary as determined by the Compensation Committee, participation in the MICP, a stock option grant, $100,000 signing bonus subject to forfeiture and severance benefits.

(9)

Mr. Santo retired from the Company effective January 1, 2003 after 27 years of service. We offer our sincere appreciation to Mr. Santo and wish him well in his future endeavors.

Option Grants in Last Fiscal Year

The following table sets forth information concerning individual grants of stock options made to the named executive officers during the fiscal year ended December 31, 2002.

	Individual Grants
Name	Number of Securities Underlying Options Granted (#)(1)		% of Total Options Granted to Employees in Fiscal Year			Exercise Price ($/Share)		Expiration Date		Grant Date Present Value ($)(2)
Stephen F. Koziar, Jr		300,000		33	%		$14.95		9/24/12		$768,000
Peter H. Forster		300,000		33	%		$14.95		9/24/12		$768,000

(1)

Options granted pursuant to the DPL Inc. Stock Option Plan on September 24, 2002. These options vest in three cumulative installments of 33 1/3% on December 31, 2002, 2003, and 2004, and become exercisable on January 1, 2005.

(2)

The grant date present value was determined using the Black-Scholes pricing model. Significant assumptions used in the model were: expected volatility 24.0%, risk-free rate of return 3.44%, dividend yield 4.28% and time of exercise 8 years.

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

The following table sets forth information concerning each exercise of stock options during fiscal 2002 by each of the named executive officers and the fiscal year-end value of unexercised options.

Name			Number of Securities Underlying Unexercised Options at Fiscal Year-End (Number)		Value of Unexercised In-the-Money Options at Fiscal Year-End ($)(1)
			Exercisable	Unexercisable	Exercisable	Unexercisable
Allen M. Hill	—	—	—	810,000	—	—
Stephen F. Koziar, Jr	—	—	—	795,000	—	117,000
Peter H. Forster	—	—	—	2,700,000	—	117,000
Elizabeth M. McCarthy	—	—	—	375,000	—	—
H. Ted Santo	—	—	—	225,000	—	—

(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, 2002.

Equity Compensation Plan Information

	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))
Plan Category	(a)		(b)		(c)
Equity compensation plans approved by security holders:

DPL Inc. Stock Option Plan		7,359,500		$20.90		642,500

Equity compensation plans not approved by security holders

Directors’ Deferred Stock Compensation Plan		232,205		N/A		See Note 1

Management Incentive Stock Plan		2,123,998		N/A		See Note 2

Total

(1)

The Directors’ Deferred Stock Compensation Plan (the “Directors’ Stock Plan) provided for the annual award of DPL Inc. 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. There was no stated maximum number of shares that may have been awarded under the Directors’ Stock Plan.

(2)

The Management Stock Incentive Plan (the “MSIP”) provided for the award of Restricted Share Units (“RSUs”) to executives. Earning of RSUs was dependent on the performance of DPL Inc. over a three-year performance period. For each RSU which was earned and vests, a participant received the equivalent of one DPL Inc. common share plus dividend equivalents from the date of award. All payouts of vested RSUs under the MSIP are deferred until retirement and are made in DPL Inc. common shares. The Stock Option Plan replaced the MSIP and no additional awards have been made under the MSIP.

Change in Control Agreements

DPL Inc. has in place agreements with each of Mr. Koziar and Ms. McCarthy providing for the payment of benefits upon the consummation of a change in control of DPL Inc. or the Company (generally, defined as the acquisition of 50% or more of the voting securities (15% or more without board approval) or certain mergers or other business combinations). The agreements require the individuals to remain with DPL Inc. throughout the period during which any change of control transaction is pending in order to help put in place the best plan for the shareholders. The principal benefits under each agreement include payment of the following: (i) 300% of the sum of the individual’s annual base salary at the rate in effect on the date of the change in control plus the average amount paid to the individual under the MICP for the three preceding years; (ii) all awarded or earned but unpaid RSUs; and (iii) continuing medical, life, and disability insurance. In addition, upon termination of the individual’s employment under specified circumstances during the pendency of a change of control, the individual is entitled to receive the individual’s full base salary and accrued benefits through the date of termination and the individual’s award for the current period under the MICP (or for a completed period if no award for that period has yet been determined) fixed at an amount equal to his average annual award paid for the preceding three years. In the event any payments under these agreements are subject to an excise tax under the Internal Revenue Code of 1986, the payments will be adjusted so that the total payments received on an after-tax basis will equal the amount the individual would have received without imposition of the excise tax. The agreements are effective for one year but are automatically renewed each year unless DPL Inc. or the participant notifies the other one year in advance of its or his or her intent not to renew. DPL Inc. is obligated at the time of a change of control to fund its obligations under the agreements and under the Directors’ and Officers’ Compensation Plans by transferring required payments to a grantor trust (the (“Master Trust”). Mr. Forster’s agreement with DPL Inc. and the Company contains similar benefits provisions.

Pension Plans

The following table sets forth the estimated total annual benefits payable under the Company retirement income plan and the supplemental executive retirement plan to executive officers at normal retirement date (age 65) based upon years of accredited service and final average annual compensation (including base and incentive compensation) for the three highest years during the last ten:

Final Average		Total Annual Retirement Benefits for Years of Accredited Service at Age 65
Annual Earnings		10 Years		15 Years		20 Years		30 Years
	$ 200,000		$ 48,288		$ 72,432		$ 96,576		$ 128,821
	400,000		105,288		157,932		210,576		242,821
	600,000		162,288		243,432		324,576		356,821
	800,000		219,288		328,932		438,576		470,821
	1,000,000		276,288		414,432		552,576		584,821
	1,200,000		233,288		499,932		666,576		698,821
	1,400,000		390,288		585,432		780,576		812,821

The years of accredited service for the named executive officers are Mr. Hill – 33 yrs.; Mr. Koziar – 33 yrs.; Ms. McCarthy – 20 yrs; and Mr. Santo – 27 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. Mr. Forster ceased to accrue benefits under the retirement plans effective upon his retirement as an employee of DPL Inc. and the Company.

Benefits paid by the supplemental plan was modified in 2000 for the named executive officers other than Ms. McCarthy and the benefits enumerated above reduced by 21%. The present value of these individual’s accrued benefit under the supplemental plan, determined by DPL Inc.’s actuary was segregated and benefits thereafter are determined on the basis of selected asset performance.

Item 12 — Security Ownership of Certain Beneficial Owners and Management

The Company’s stock is actually owned by DPL Inc.

Item 13 — Certain Relationships and Related Transactions

None.

Item 14 — Controls and Procedures

Within 90 days prior to the filing date of this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There were no significant changes in the Company’s internal controls or in other factors that could significantly affect internal controls subsequent to the date of their evaluation.

PART IV

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

(a)

Documents filed as part of the Form 10-K

1. Financial Statements

See Item 8 - Index to Consolidated Financial Statements.

2. Financial Statement Schedule

See Item 8 - Index to Financial Statement Schedule

3. Exhibits

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

		Incorporated Herein by Reference as Filed With
2(a)	Copy of the Agreement of Merger among DPL Inc., Holding Sub Inc. and the Company dated January 6, 1986	Exhibit A to the 1986 Proxy Statement (File No. 1-2385)

2(b)	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. 1-2385)

3(a)	Regulations and By-Laws of the Company	Exhibit 2(e) to Registration Statement No. 2-68136 to Form S-16

3(b)	Copy of Amended Articles of Incorporation of the Company dated January 3, 1991	Exhibit 3(b) to Report on Form 10-K for the year ended December 31, 1991 (File No. 1-2385)

4(a)	Copy of Composite Indenture dated as of October 1, 1935, between the Company 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 the Thirtieth Supplemental Indenture dated as of March 1, 1982, between the Company and The Bank of New York, Trustee	Exhibit 4(h) to Registration Statement No. 33-53906

4(c)	Copy of the Thirty-First Supplemental Indenture dated as of November 1, 1982, between the Company and The Bank of New York, Trustee	Exhibit 4(h) to Registration Statement No. 33-56162

4(d)	Copy of the Thirty-Second Supplemental Indenture dated as of November 1, 1982, between the Company and The Bank of New York, Trustee	Exhibit 4(i) to Registration Statement No. 33-56162

4(e)	Copy of the Thirty-Third Supplemental Indenture dated as of December 1, 1985, between the Company and The Bank of New York, Trustee	Exhibit 4(e) to Report on Form 10-K for the year ended December 31, 1985 (File No. 1-2385)

4(f)	Copy of the Thirty-Fourth Supplemental Indenture dated as of April 1, 1986, between the Company and The Bank of New York, Trustee	Exhibit 4 to Report on Form 10-Q for the quarter ended June 30, 1986 (File No. 1-2385)

4(g)	Copy of the Thirty-Fifth Supplemental Indenture dated as of December 1, 1986, between the Company and The Bank of New York, Trustee	Exhibit 4(h) to Report on Form 10-K for the year ended December 31, 1986 (File No. 1-9052)

4(h)	Copy of the Thirty-Sixth Supplemental Indenture dated as of August 15, 1992, between the Company and The Bank of New York, Trustee	Exhibit 4(i) to Registration Statement No. 33-53906

4(i)	Copy of the Thirty-Seventh Supplemental Indenture dated as of November 15, 1992, between the Company and The Bank of New York, Trustee	Exhibit 4(j) to Registration Statement No. 33-56162

4(j)	Copy of the Thirty-Eighth Supplemental Indenture dated as of November 15, 1992, between the Company and The Bank of New York, Trustee	Exhibit 4(k) to Registration Statement No. 33-56162

4(k)	Copy of the Thirty-Ninth Supplemental Indenture dated as of January 15, 1993, between the Company and The Bank of New York, Trustee	Exhibit 4(k) to Registration Statement No. 33-57928

4(l)	Copy of the Fortieth Supplemental Indenture dated as of February 15, 1993, between the Company and The Bank of New York, Trustee	Exhibit 4(m) to Report on Form 10-K for the year ended December 31, 1992 (File No. 1-2385)

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

4(n)	Copy of the Revolving Credit Agreement dated as December 18, 2002, between the Company, Keybank National Association (as agent), Bank One, NA (as agent), and the banks named therein	Filed herewith as Exhibit 4(n)

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. 1-2385)

10(b) *	Copy of Directors’ Deferred Compensation Plan amended December 31, 2000	Exhibit 10(b) to Report on Form 10-K for the year ended December 31, 2000 (File No. 1-2385)

10(c) *	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. 1-2385)

10(d) *	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. 1-2385)

10(e) *	Form of Change of Control Agreement with Certain Executive Officers	Exhibit 10(e) to Report on Form 10-K for the year ended December 31, 2000 (File No. 1-2385)

10(f) *	Copy of Stock Option Plan	Exhibit 10(f) to Report on Form 10-K for the year ended December 31, 2000 (File No. 1-2385)

10(g)*	Consulting contract dated as of December 31, 1996 between DPL Inc. and Peter H. Forster	Filed herewith as Exhibit 10(g)

10(h)*	Employment agreement dated as of March 21, 2000 between DPL Inc. and Elizabeth M. McCarthy	Filed herewith as Exhibit 10(h)

10(i)*	Employment agreement dated as of October 17, 2002 between DPL Inc. and Stephen F. Koziar	Filed herewith as Exhibit 10(i)

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, 1988 (File No. 1-2385)

21	Copy of List of Subsidiaries of the Company	Filed herewith as Exhibit 21

* Management contract or compensatory plan.

(b)

Reports on Form 8-K

None.

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 Registrant
February 19, 2003		/s/ Elizabeth M. McCarthy

		Elizabeth M. McCarthy Group Vice President and Chief Financial Officer (principal financial officer)


February 19, 2003		/s/ Stephen F. Koziar

		Stephen F. Koziar 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/ T. J. Danis (T. J. Danis)	Director	February 19, 2003


/s/ J. F. Dicke, II (J. F. Dicke, II)	Director	February 19, 2003


/s/ P. H. Forster (P. H. Forster)	Director and Chairman	February 19, 2003


/s/ E. Green (E. Green)	Director	February 19, 2003


(J. G. Haley)	Director	February 19, 2003


/s/ W. A. Hillenbrand (W A. Hillenbrand)	Director	February 19, 2003


(D. R. Holmes)	Director	February 19, 2003


/s/ S. F. Koziar (S. F. Koziar)	Director, President and Chief Executive Officer	February 19, 2003


/s/ B. R. Roberts (B. R. Roberts)	Director	February 19, 2003


(G. R. Roberts)	Director	February 19, 2003


/s/ S. M. Stuart (S. M. Stuart)	Director	February 19, 2003


/s/ E. M. McCarthy (E. M. McCarthy)	Group Vice President and Chief Financial Officer (principal financial officer)	February 19, 2003

CERTIFICATIONS

I, Elizabeth M. McCarthy, certify that:

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

Based on my knowledge, this annual 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 annual report;

Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual report;

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures 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 annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date:		February 19, 2003
Signature:		/s/ Elizabeth M. McCarthy
Print Name:		Elizabeth M. McCarthy
Title:		Group Vice President and Chief Financial Officer

CERTIFICATIONS

I, Stephen F. Koziar, certify that:

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

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date:		February 19, 2003
Signature:		/s/ Stephen F. Koziar
Print Name:		Stephen F. Koziar
Title:		President and Chief Executive Officer

Schedule II

The Dayton Power and Light Company
VALUATION AND QUALIFYING ACCOUNTS

For the years ended December 31, 2002, 2001, and 2000

($ in thousands)


COLUMN A	COLUMN B		COLUMN C				COLUMN D		COLUMN E

			Additions
Description	Balance at Beginning of Period		Charged to Income		Other		Deductions (1)		Balance at End of Period

2002:
Deducted from accounts receivable—

Provision for uncollectible accounts	$	12,445	$	3,008	$	—	$	4,580	$	10,873

2001:
Deducted from accounts receivable—

Provision for uncollectible accounts	$	6,847	$	11,759	$	—	$	6,161	$	12,445

2000:
Deducted from accounts receivable—

Provision for uncollectible accounts	$	4,332	$	9,115	$	—	$	6,600	$	6,847

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

|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934

PART I

THE COMPANY

COMPETITION

CONSTRUCTION PROGRAM

ELECTRIC OPERATIONS AND FUEL SUPPLY

GAS OPERATIONS AND GAS SUPPLY

RATE REGULATION AND GOVERNMENT LEGISLATION

ENVIRONMENTAL CONSIDERATIONS

Air Quality

Land Use

The Dayton Power and Light CompanyOPERATING STATISTICS ELECTRIC OPERATIONS

The Dayton Power and Light CompanyOPERATING STATISTICSGAS OPERATIONS

Electric

Gas

PART II

Overview

Income Statement Highlights

Construction Program and Financing

Market Risk

Critical Accounting Policies

Issues and Financial Risks

The Dayton Power and Light Company

CONSOLIDATED STATEMENT OF RESULTS OF OPERATIONS

The Dayton Power and Light Company

CONSOLIDATED STATEMENT OF CASH FLOWS

The Dayton Power and Light Company

CONSOLIDATED BALANCE SHEETS

The Dayton Power and Light Company

The Dayton Power and Light Company

CONSOLIDATED STATEMENT OF SHAREHOLDER’S EQUITY

The Dayton Power and Light Company

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Revenues and Fuel

Property, Maintenance and Depreciation

Repairs and Maintenance

Stock-Based Compensation Cost

Income Taxes

Consolidated Statement of Cash Flows

Financial Derivatives

2. Recent Accounting Standard

3. Sale of the Gas Business

4. Regulatory Matters

5. Income Taxes

Components of Deferred Tax Assets and Liabilities

6. Pensions and Postretirement Benefits

Pensions

Postretirement Benefits

7. Preferred Stock

8. Long-term Debt

9. Notes Payable and Compensating Balances

10. Employee Stock Plans

11. Ownership of Facilities

12. Fair Value of Financial Instruments

13. Business Segment Reporting

SELECTED QUARTERLY INFORMATION (Unaudited)

FINANCIAL AND STATISTICAL SUMMARY (Unaudited)

Report of Independent Accountants

PART III

Directors of the Registrant

COMPENSATION OF DIRECTORS

EXECUTIVE OFFICER COMPENSATION

Summary Compensation Table

Option Grants in Last Fiscal Year

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

Equity Compensation Plan Information

Change in Control Agreements

Pension Plans

PART IV

SIGNATURES

CERTIFICATIONS

CERTIFICATIONS

Schedule II

|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

The Dayton Power and Light Company
OPERATING STATISTICS
ELECTRIC OPERATIONS

The Dayton Power and Light Company
OPERATING STATISTICS
GAS OPERATIONS