10-K405 1 d10k405.txt FORM 10-K 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, 2001 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 31-0258470 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 1065 Woodman Drive, Dayton, Ohio 45432 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: 937-224-6000 Securities registered pursuant to Section 12(b) of the Act: 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. [X] 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 [ ] Number of shares of registrant's common stock outstanding as of February 28, 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, 2001
Page No. Part I Item 1 Business...................................................................................... 3 Item 2 Properties.................................................................................... 14 Item 3 Legal Proceedings............................................................................. 14 Item 4 Submission of Matters to a Vote of Security Holders........................................... 14 Part II Item 5 Market for Registrant's Common Equity and Related Shareholder Matters......................... 14 Item 6 Selected Financial Data....................................................................... 15 Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations......... 15 Item 7A Quantitative and Qualitative Disclosure about Market Risk..................................... 22 Item 8 Financial Statements and Supplementary Data................................................... 23 Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......... 45 Part III Item 10 Directors and Executive Officers of the Registrant............................................ 45 Item 11 Executive Compensation........................................................................ 49 Item 12 Security Ownership of Certain Beneficial Owners and Management................................ 53 Item 13 Certain Relationships and Related Transactions................................................ 53 Part IV Item 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K............................... 54 Other Signatures.................................................................................... 58
2 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 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 1,539 persons as of December 31, 2001, of which 1,298 were full-time employees and 241 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, at which time the Company's generation assets will no longer be subject to Ohio regulation and will be able to sell all capacity in the open energy market. The plan also provides for a 5% residential rate reduction on the generation component of the rates, which reduces revenue by approximately $13-14 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 without regulatory restrictions. On September 30, 1996, the FERC conditionally accepted the Company's market-based sales tariff, which will allow the Company to sell wholesale generation supply at prices that reflect current market prices. 3 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 National Energy Policy Act of 1992, which reformed the Public Utilities Holding Company Act of 1935, allows the federal government to mandate access by others to a utility's electric transmission system and may accelerate competition in the supply of electricity. 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 1.7% of total electricity sales in 2001. 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 Federal Energy Regulatory Commission ("FERC") claiming violation of a mediation clause. On June 29, 2000 the FERC Administrative Law Judge issued an initial decision in the case, which was favorable to the Company; however, the FERC has not yet issued a final order. This dispute is expected to be resolved through the FERC process, and is not expected to result in a material impact on the Company's financial position or results of operations. On April 24, 1996, the FERC issued orders requiring all electric utilities that own or control transmission facilities to file open-access transmission service tariffs. Open-access transmission tariffs provide third parties with non-discriminatory transmission service comparable to what the utility provides itself. In its orders, the FERC further stated that FERC-jurisdictional stranded costs reasonably incurred and costs of complying with the rules will be recoverable by electric utilities. Both in 1997 and 1998, the Company reached an agreement in principle with staff and intervenors in these tariff cases. The FERC issued an Order accepting the Stipulation between the parties in the Company's Open Access Transmission Tariff cases on July 30, 1999 and September 17, 1999. The Company was not materially impacted by the Order. FERC issued a final rule on December 20, 1999 specifying the minimum characteristics and functions for Regional Transmission Organizations ("RTO"). The rule required that 4 all public utilities that own, operate or control interstate transmission 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 that did not approve the Alliance RTO as a stand-alone regional transmission organization. As of December 31, 2001, the Company had invested approximately $6 million in its efforts to join the Alliance RTO. The Company is exploring its operational and financial options as a result of the FERC Order. 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 July 22, 1998, the PUCO approved the implementation of Minimum Electric Service 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 are 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. In October 2000, the Company completed the sale of its natural gas retail distribution assets and certain liabilities for $468 million in cash. CONSTRUCTION PROGRAM Construction additions are expected to approximate $133 million in 2002, and were $164 million in 2001 and $125 million in 2000. The capital program includes environmental compliance, which is expected to approximate $64 million in 2002, and was $58 and $15 million in 2001 and 2000, 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 2002 and 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. 5 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 ------------------ Operating Company Station Ownership* Company Location 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 Turbine 1 W Company Moraine, OH 100 100 Tait Gas Turbine 2 W Company Moraine, OH 102 102 Tait Gas Turbine 3 W Company Moraine, OH 102 102 Killen C Company Wrightsville, OH 16 24 Stuart C Company Aberdeen, OH 3 10
*W = Wholly-Owned C = Commonly Owned 6 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 99% of its electric output from coal-fired units in 2001. The remainder was from oil or natural gas-fired units, which were used to meet peak demands. The Company has contracted approximately 95% and 74% of its total coal requirements for 2002 and 2003, respectively, 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 1.31(cent) in 2001, 1.18(cent) in 2000 and 1.30(cent) in 1999. 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 ($121 million net of taxes). Proceeds from the sale were used to finance DPL's regional generation expansion and reduce outstanding short-term debt. RATE REGULATION AND GOVERNMENT LEGISLATION The Company's sales to retail customers are subject to rate regulation by the PUCO and various municipalities. The Company's wholesale electric rates to municipal corporations and other distributors of electric energy are subject to regulation by the FERC under the Federal Power Act. Ohio law establishes the process for determining rates charged by public utilities. Regulation of rates encompasses the timing of applications, the effective date of rate increases, the cost basis upon which the rates are based and other related matters. Ohio law also establishes the Office of the Ohio Consumers' Counsel (the "OCC"), which has the authority to represent residential consumers in state and federal judicial and administrative rate proceedings. Ohio legislation extends the jurisdiction of the PUCO to the records and accounts of certain public utility holding company systems, including DPL. The legislation extends 7 the PUCO's supervisory powers to a holding company system's general condition and capitalization, among other matters, to the extent that they relate to the costs associated with the provision of public utility service. Based on existing regulatory authorization, regulatory assets on the Consolidated Balance Sheet include: At December 31, ($ in millions) 2001 2000 ------ ------ Regulatory transition costs (a) ....................... $ 97.2 $144.8 Income taxes recoverable through future revenues (b) ............................... 39.2 49.4 Other costs (b) ....................................... 2.5 1.6 ------ ------ Total ................................................. $138.9 $195.8 ====== ====== (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: 8 Name Beginning of Term End of Term ---- ----------------- ----------- Clarence D. Rogers........................... February 2001 April 2006 Rhonda H. Fergus............................. April 1995 April 2005 Chairman Alan R. Schriber.................... April 1999 April 2004 Donald L. Mason.............................. April 1998 April 2003 Judith A. Jones.............................. April 1997 April 2002 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 ("NOV's") 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. The outcome of these claims or the impact, if any, on the Company has not been determined. 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 NOV's and 9 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, the outcome of these claims or the impact, if any, on the Company is unknown. 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 2003. In order to meet these NOx requirements, the Company's total capital expenditures are estimated to be approximately $175 million, of which $94 million remains to be expended by May 2004. 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 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. 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 Sanitary Landfill Site on Cardington Road in Montgomery County, Ohio; the North Sanitary (a.k.a. Valleycrest) Landfill in Dayton, Montgomery County, Ohio; and the Tremont City Landfill in Springfield, Ohio. The Company received notification from the USEPA in July 1987 for the Cardington Road site. The Company has not joined the PRP group formed at that site because of the absence of any known evidence that the Company contributed hazardous substances to this site. In September 2001, the Court entered and finalized DP&L's settlements with the USEPA for this site. These settlements fully resolve DP&L's liabilities for this site and did not have a material effect on the Company's financial position, earnings, or cash flow. 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 10 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. 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 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. 11 The Dayton Power and Light Company OPERATING STATISTICS ELECTRIC OPERATIONS Years Ended December 31 ------------------------------------ 2001 2000 1999 ---------- ---------- ---------- Electric Sales (millions of kWh) Residential .......................... 4,909 4,816 4,725 Commercial ........................... 3,618 3,540 3,390 Industrial ........................... 4,568 4,851 4,876 Other retail ......................... 1,369 1,370 1,306 ---------- ---------- ---------- Total Retail ...................... 14,464 14,577 14,297 Wholesale ............................ 3,591 2,946 2,570 ---------- ---------- ---------- Total ............................. 18,055 17,523 16,867 ========== ========== ========== Electric Revenues (thousands) Residential .......................... $ 429,932 $ 422,733 $ 412,808 Commercial ........................... 255,149 245,097 235,309 Industrial ........................... 210,022 236,670 242,410 Other retail ......................... 92,992 93,227 88,809 ---------- ---------- ---------- Total Retail ...................... 988,095 997,727 979,336 Wholesale ............................ 200,154 112,328 79,008 ---------- ---------- ---------- Total ............................. $1,188,249 $1,110,055 $1,058,344 ========== ========== ========== Electric Customers at End of Period Residential .......................... 445,969 444,683 441,468 Commercial ........................... 46,700 46,218 45,470 Industrial ........................... 1,903 1,928 1,917 Other ................................ 6,302 6,156 6,040 ---------- ---------- ---------- Total ............................. 500,874 498,985 494,895 ========== ========== ========== NOTE: See Note 14 to Consolidated Financial Statements for additional information. 12 The Dayton Power and Light Company OPERATING STATISTICS GAS OPERATIONS Years Ended December 31 -------------------------- 2001 2000 1999 ---- -------- -------- Gas Sales (thousands of MCF) Residential ................................... -- 18,538 24,450 Commercial .................................... -- 5,838 7,647 Industrial .................................... -- 2,034 2,246 Public authorities ............................ -- 776 1,182 Transportation gas delivered .................. -- 16,105 20,190 ---- -------- -------- Total ...................................... -- 43,291 55,715 ==== ======== ======== Gas Revenues (thousands) Residential ................................... -- $119,460 $139,545 Commercial .................................... -- 35,262 40,225 Industrial .................................... -- 11,114 11,017 Public authorities ............................ -- 4,466 5,908 Other ......................................... -- 13,554 18,284 ---- -------- -------- Total ...................................... -- $183,856 $214,979 ==== ======== ======== Gas Customers at End of Period Residential ................................... -- -- 282,706 Commercial .................................... -- -- 22,635 Industrial .................................... -- -- 1,303 Public authorities ............................ -- -- 1,173 ---- -------- -------- Total ...................................... -- -- 307,817 ==== ======== ======== NOTE: 1) The Company completed the sale of its natural gas retail distribution assets and certain liabilities in October 2000. 2) See Note 14 to Consolidated Financial Statements for additional information. 13 Item 2 - Properties -------------------------------------------------------------------------------- Electric Information relating to the Company's electric properties is contained in Item 1 - BUSINESS, THE COMPANY (page 3), CONSTRUCTION PROGRAM (pages 5-6), ELECTRIC OPERATIONS AND FUEL SUPPLY (pages 6-7) and Item 8 - Notes 4 and 11 of Notes to Consolidated Financial Statements on pages 31-32 and 39-40, respectively, which pages are incorporated herein by reference. Gas Information relating to the Company's gas properties is contained in Item 1 - BUSINESS, THE COMPANY (page 3), and GAS OPERATIONS AND GAS SUPPLY (page 7) and Note 3 of Notes to Consolidated Financial Statements (page 31), which pages are incorporated herein by reference. 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 (page 3), COMPETITION (pages 3-5), ELECTRIC OPERATIONS AND FUEL SUPPLY (pages 6-7), RATE REGULATION AND GOVERNMENT LEGISLATION (pages 7-9), ENVIRONMENTAL CONSIDERATIONS (pages 9-11) and Item 8 - Note 4 of Notes to Consolidated Financial Statements on pages 31-32, which pages are incorporated herein by reference. 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 on page 42 and the Financial and Statistical Summary on page 43, which pages are incorporated herein by reference. 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 14 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 on page 43, which page is incorporated herein by reference. 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 $240.4 million, an increase of 9% over 2000 earnings on common stock of $221.0 million in 2000 and up 25% from earnings on common stock of $191.6 million in 1999. (Earnings on common stock numbers are before extraordinary and non-recurring items.) Growth from increased wholesale sales and sales of capacity from 2001 and 2000 peaking generation capacity additions were the primary drivers. Results for 2001 included net non-recurring items of $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 non-recurring events affected 2000 financial results as outlined below: 15 $ in millions 2001 2000 1999 ---------------------------------------------------------------------------- Earnings on Common Stock after non- recurring and extraordinary items ......... $234.4 $ 297.9 $191.6 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 non- recurring and extraordinary items ......... $240.4 $ 221.0 $191.6 Income Statement Highlights $ in millions 2001 2000 1999 ----------------------------------------------------------------------------- Electric: Revenues ............................. $1,188.2 $1,110.1 $1,058.3 Fuel and purchased power ............. 349.9 286.1 263.2 -------- -------- -------- Net revenues ..................... 838.3 824.0 795.1 Gas Utility: (a) Revenues ............................. -- 183.8 215.0 Gas purchased for resale ............. -- 116.9 129.9 -------- -------- -------- Net revenues ..................... -- 66.9 85.1 (a) The Company completed the sale of its natural gas retail distribution assets and certain liabilities in October 2000. In 2001, net electric revenues increased $14.3 million or 2% 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 current economic conditions and mild weather, which reduced overall retail sales by 1%. Fuel costs for existing generation increased as a result of higher spot-market prices for coal, and greater fuel usage and power purchases resulting from increased wholesale sales. In 2000, net electric revenues increased $28.9 million or 4% as a result of higher wholesale and retail sales, and the addition of peaking generation capacity sales. The effect of these increased sales on fuel and purchased power costs were offset by lower fuel expense used in generation. The decline in net gas revenues for both 2001 and 2000 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 $26.8 million or 14% in 2001 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 16 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. Operation and maintenance expense decreased $12.8 million or 6% in 2000 as a result of lower employee benefit costs and natural gas retail distribution system expense, partially offset by higher insurance and claims costs, uncollectibles, and power production costs. 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 11% and 3% in 2001 and 2000, respectively, 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 decreased $29.7 million or 23% in 2001 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 $144.8 million or 85% in 2001 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 under the Company's business interruption policy related to deregulation (see Issues and Financial Risks - Other Matters), and costs associated with the elimination of certain compensation programs in 2000. Other income (deductions) increased $156.6 million in 2000 as a result of the $182.5 million gain, partially offset by costs as described above, property donations, stock compensation expense, and the November 1999 transfer of the Company's ownership interest in the assets and liabilities of MVE, Inc. to Plaza Building, Inc., which is another wholly-owned subsidiary of DPL. Interest expense decreased 14% and 11% in 2001 and 2000, respectively, primarily as a result of higher capitalized interest. 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 17 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 $133 million in 2002, and were $164 million in 2001 and $125 million in 2000. The capital program includes environmental compliance, which is expected to approximate $64 million in 2002, and was $58 and $15 million in 2001 and 2000, 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 2002 and 2003 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 its subsidiaries have $200 million available through revolving credit agreements with a consortium of banks. Facility fees are approximately $0.3 million per year. The primary purpose of the revolving credit facilities is to provide back-up liquidity for the commercial paper program. The Company had no borrowings outstanding under these credit agreements at December 31, 2001 and 2000. The Company also has $75.0 million available in short-term informal lines of credit. The commitment fees are not material. The Company had no borrowings outstanding under these informal lines and no outstanding commercial paper balances at December 31, 2001 and 2000. 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 2002-2006. At year-end 2001, the Company's senior debt credit ratings were as follows: Standard & Poor's Corp........... BBB+ Moody's Investors Service........ A2 18 Market Risk The carrying value of the Company's debt was $668.1 million at December 31, 2001, consisting of the Company's first mortgage bonds and guaranteed air quality development obligations. The fair value of this debt was $678.8 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table presents the principal cash repayments and related weighted average interest rates by maturity date for long-term, fixed-rate debt at December 31, 2001. Long-term Debt ------------------------------------- Expected Maturity Date Amount ($ in millions) Average Rate -------------------------------------------------------------- 2002 $ 1.1 7.4% 2003 1.1 7.4% 2004 1.1 7.4% 2005 1.1 7.4% 2006 1.1 7.4% Thereafter 662.6 7.5% ------ Total $668.1 7.5% ====== Fair Value $678.8 ====== 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, 2001, the Company had no short-term debt outstanding, and therefore, no exposure to short-term interest rate risk. The Company's financial results are impacted by changes in electricity, coal, and gas commodity prices. Ten percent of the Company's expected 2002 revenues are from spot energy sales in the wholesale market and sales of peaking capacity. Fuel and purchased power costs represented 39% of total operating costs in 2001. The Company has contracted for 95% of its total coal needs for 2002. A 2% change in overall fuel costs would result in a $3.5 million change in net income. 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 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. 19 The transition plan provides for a three-year transition period, which began on January 1, 2001 and ends on December 31, 2003, at which time the Company's generation assets will no longer be subject to Ohio regulation and will be able to sell all capacity in the open energy markets. The plan also provides for a 5% residential rate reduction on the generation component of the rates, which reduces revenue by approximately $13-14 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 without regulatory restrictions. In 1996 and 1997, the Federal Energy Regulatory Commission ("FERC") issued orders requiring all electric utilities to file open-access transmission service tariffs. The Company's resulting tariff case proceedings with FERC staff and intervenors in 1997 and 1998 culminated in 1999 with the FERC issuing an Order approving the Company's settlement with no material adverse effect to the Company. On October 16, 2000 the Company filed with the FERC to join the Alliance Regional Transmission Organization ("Alliance RTO"). On December 19, 2001 the FERC issued an Order that did not approve the Alliance RTO as a stand-alone regional transmission organization. As of December 31, 2001, the Company had invested approximately $6 million in its efforts to join the Alliance RTO. The Company is exploring its operational and financial options as a result of the FERC Order. 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. 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 ("NOV's") against operators and owners of certain generation facilities for alleged violations of the Clean Air Act ("CAA"). Generation units operated by partners Cincinnati Gas & Electric Company (Beckjord 6) and Columbus Southern Power Company (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 NOV's, civil complaints or state actions. In December 2000, Cincinnati Gas & Electric Company 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. The outcome of these claims or the impact, if any, on the 20 Company has not been determined. In June 2000, the USEPA issued a NOV to DP&L-operated J.M. Stuart Station (co-owned by DP&L, Cincinnati Gas & Electric Company, and Columbus Southern Power Company) for alleged violations of the CAA. The NOV contained allegations consistent with NOV's 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, the outcome of these claims or the impact, if any, on the Company is unknown. The United States and Ohio EPA's have notified numerous parties, including the Company, that they are considered Potentially Responsible Parties ("PRP's") for clean up of three hazardous waste sites in Ohio. In September 2001, the Court entered and finalized the Company's settlements with the USEPA for the first site. The Company also settled with the PRP group for the site. These settlements fully resolve the Company's liability for this site and did not have a material effect on the Company's financial position, earnings, or cash flow. The Ohio EPA has not provided an estimated cost for the second site. In October 2000, the PRP group at the second site brought an action against the Company and numerous other parties to recover a portion of the clean-up costs. The Company will vigorously challenge this action. In January 2002, the Company and seventy-five other parties received notification from the USEPA that they might be PRP's for clean up of hazardous substances at a third 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 of these matters are not expected 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 ("SIP's") under the CAA. The modified SIP's are likely to result in further Nitrogen Oxide ("NOx") reduction requirements placed on coal-fired generating units by 2003. In order to meet these NOx requirements, the Company's total capital expenditures are estimated to be approximately $175 million, of which $94 million remains to be expended by May 2004. Industry groups and others appealed the rules in the 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 rules an additional year, until May 31, 2004. 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 to meet the SIP call is expected to satisfy the rulemaking 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. 21 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. 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 includes insurance reserves of approximately $87 million 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. In 2001, a $29 million receivable was recognized by DP&L for insurance claims under its business interruption policy. In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143") that addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets. SFAS No. 143 is effective for the Company as of January 1, 2003. The Company has not yet determined the extent to which its financial condition or results of operations may be affected by the implementation of this accounting standard. Item 7A - Quantitative and Qualitative Disclosures about Market Risk -------------------------------------------------------------------- Information relating to Market Risk is contained in Item 7 - Management's Discussion and Analysis (page 19). 22 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, 2001................................................................ 24 Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2001........................................................................... 25 Consolidated Balance Sheet as of December 31, 2001 and 2000....................................... 26-27 Consolidated Statement of Shareholder's Equity for the three years in the period ended December 31, 2001................................................................ 28 Notes to Consolidated Financial Statements........................................................ 29-42 Report of Independent Accountants................................................................. 44
Index to Supplemental Information Page No. --------------------------------- -------- Selected Quarterly Information.................................................................... 42 Financial and Statistical Summary................................................................. 43
23 The Dayton Power and Light Company CONSOLIDATED STATEMENT OF RESULTS OF OPERATIONS
-------------------------------------------------------------------------------------------------------------- For the years ended December 31, $ in millions 2001 2000 1999 ------------------------------------------------------------------------------------------------------------- Revenues Electric .................................................................. $1,188.2 $1,110.1 $1,058.3 Gas (Note 3)............................................................... -- 183.8 215.0 -------- -------- -------- Total revenues........................................................ 1,188.2 1,293.9 1,273.3 -------- -------- -------- Expenses Fuel and purchased power................................................... 349.9 286.1 263.2 Gas purchased for resale (Note 3).......................................... -- 116.9 129.9 Operation and maintenance............................................. .... 164.3 191.1 203.9 Depreciation and amortization.............................................. 116.0 130.3 134.0 Amortization of regulatory assets, net (Note 4)............................ 46.9 16.3 24.9 General taxes.............................................................. 98.7 128.4 136.4 -------- -------- -------- Total expenses.................................................... 775.8 869.1 892.3 -------- -------- -------- Operating Income........................................................... 412.4 424.8 381.0 Other income (deductions) (Note 3)......................................... 25.9 170.7 14.1 Interest expense........................................................... (62.6) (72.7) (81.5) -------- -------- -------- Income Before Income taxes, Extraordinary Item, and Cumulative Effect of Accounting Change.......................................................... 375.7 522.8 313.6 Income taxes............................................................... 141.4 182.6 121.1 -------- -------- -------- Income Before Extraordinary Item and Cumulative Effect of Accounting Change........................................... 234.3 340.2 192.5 Extraordinary item, net of tax........................................ -- 41.4 -- Cumulative effect of accounting change, net of tax.................... 1.0 -- -- -------- -------- -------- Net Income............................................................ 235.3 298.8 192.5 Preferred dividends................................................... 0.9 0.9 0.9 -------- -------- -------- Earnings on Common Stock.............................................. $ 234.4 $ 297.9 $ 191.6 ======== ======== ========
See Notes to Consolidated Financial Statements. 24 The Dayton Power and Light Company CONSOLIDATED STATEMENT OF CASH FLOWS
----------------------------------------------------------------------------------------------- For the years ended December 31, $ in millions 2001 2000 1999 ----------------------------------------------------------------------------------------------- Operating Activities Cash received from utility customers .................. $1,185.6 $1,297.3 $1,280.1 Other operating cash receipts ......................... 64.5 22.7 30.0 Cash paid for: Fuel and purchased power .......................... (365.3) (269.9) (263.8) Purchased gas (Note 3) ............................ (51.5) (156.5) (135.9) Operation and maintenance labor ................... (72.1) (81.1) (72.8) Nonlabor operating expenditures ................... (99.5) (165.9) (113.8) Interest .......................................... (57.4) (69.2) (79.2) Income taxes ...................................... (132.4) (152.6) (106.6) General taxes ..................................... (138.7) (139.3) (136.7) -------- -------- -------- Net cash provided by operating activities ............. 333.2 285.5 401.3 -------- -------- -------- Investing Activities Capital expenditures .................................. (161.5) (109.9) (80.3) Purchases of available-for-sale financial assets ...... -- -- (276.9) Sales of available-for-sale financial assets .......... -- -- 61.1 Proceeds from sale of natural gas retail distribution operations, net (Note 3) ............. (90.9) 468.2 -- -------- -------- -------- Net cash provided by (used for) investing activities... (252.4) 358.3 (296.1) -------- -------- -------- Financing Activities Dividends paid on common stock ........................ (82.4) (606.4) (130.3) Issuance (retirement) of short-term debt .............. -- (123.0) 112.2 Parent company capital contribution ................... -- -- 245.0 Retirement of long-term debt .......................... (0.4) (0.4) (237.6) Dividends paid on preferred stock ..................... (0.9) (0.9) (0.9) -------- -------- -------- Net cash used for financing activities ................ (83.7) (730.7) (11.6) -------- -------- -------- Cash and temporary cash investments-- Net change ........................................ (2.9) (86.9) 93.6 Balance at beginning of period .................... 8.6 95.5 1.9 -------- -------- -------- Balance at end of period .......................... $ 5.7 $ 8.6 $ 95.5 ======== ======== ========
See Notes to Consolidated Financial Statements. 25 The Dayton Power and Light Company CONSOLIDATED BALANCE SHEET ------------------------------------------------------------------------------- At December 31, $ in millions 2001 2000 ------------------------------------------------------------------------------- Assets Property Property .............................................. $ 3,684.4 $ 3,522.6 Accumulated depreciation and amortization ............. (1,670.0) (1,560.4) --------- --------- Net property ................................. 2,014.4 1,962.2 --------- --------- Current Assets Cash and temporary cash investments ................... 5.7 8.6 Accounts receivable,less provision for uncollectible accounts of $12.4 and $6.8 respectively .......... 179.1 189.7 Inventories, at average cost .......................... 61.3 45.7 Prepaid taxes ......................................... 54.8 65.4 Other ................................................. 49.8 35.5 --------- --------- Total current assets ............................. 350.7 344.9 --------- --------- Other Assets Income taxes recoverable through future revenues ......................................... 39.2 49.4 Other regulatory assets ............................... 99.7 146.4 Trust assets .......................................... 141.1 171.8 Other assets .......................................... 75.8 76.4 --------- --------- Total other assets ............................... 355.8 444.0 --------- --------- Total Assets $ 2,720.9 $ 2,751.1 ========= ========= See Notes to Consolidated Financial Statements. 26 The Dayton Power and Light Company CONSOLIDATED BALANCE SHEET (continued) ----------------------------------------------------------------------- At December 31, $ in millions 2001 2000 ----------------------------------------------------------------------- Capitalization and Liabilities Capitalization Common shareholder's equity Common stock ............................... $ 0.4 $ 0.4 Other paid-in capital ...................... 771.6 769.8 Accumulated other comprehensive income ..... 15.6 37.3 Earnings reinvested in the business ........ 357.3 205.4 -------- -------- Total common shareholder's equity ...... 1,144.9 1,012.9 Preferred stock ................................. 22.9 22.9 Long-term debt .................................. 666.6 666.5 -------- -------- Total capitalization ................... 1,834.4 1,702.3 -------- -------- Current Liabilities Accounts payable ................................ 133.5 103.9 Accrued taxes ................................... 105.6 220.0 Accrued interest ................................ 19.0 19.1 Other ........................................... 21.6 14.3 -------- -------- Total current liabilities .............. 279.7 357.3 -------- -------- Deferred Credits And Other Deferred taxes .................................. 397.0 429.9 Unamortized investment tax credit ............... 58.0 60.2 Trust obligations ............................... 102.7 113.6 Other ........................................... 49.1 87.8 -------- -------- Total deferred credits and other ....... 606.8 691.5 -------- -------- Total Capitalization and Liabilities ............ $2,720.9 $2,751.1 ======== ======== See Notes to Consolidated Financial Statements. 27 The Dayton Power and Light Company CONSOLIDATED STATEMENT OF SHAREHOLDER'S EQUITY
Common Stock (a) Accumulated Earnings -------------------- Other Reinvested Outstanding Other Paid-In Comprehensive in the $ in millions Shares Amount Capital Income Business Total -------------------------------------------------------------------------------------------------------------------- 1999: Beginning balance 41,172,173 $0.4 $788.2 $33.6 $450.8 $1,273.0 Comprehensive income: Net income...................... 192.5 Unrealized gains, net of reclassification adjustments, after tax (b)................. 4.1 Total comprehensive income........ 196.6 Common stock dividends............ (129.7) (129.7) Dividend-in-kind (c) (Note 1)..... (24.1) (24.1) Dividend-in-kind (Note 1)......... (263.6) 1.4 (262.2) Preferred stock dividends......... (0.9) (0.9) Parent company capital contribution.................... 245.0 245.0 Other............................. 0.1 (0.2) (0.1) --------------------------------------------------------------------------- Ending balance.................... 41,172,173 0.4 769.7 13.6 513.9 1,297.6 2000: 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 ===========================================================================
(a) 50,000,000 shares authorized. (b) Net of taxes of $2.2, $12.8, and $8.0 million in 1999, 2000, and 2001, respectively. (c) Net of taxes of $13.1 million in 1999. See Notes to Consolidated Financial Statements. 28 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. In 1999, the Company transferred its ownership interests in the assets and liabilities of MacGregor Park, Inc. and DP&L Community Urban Redevelopment Corporation to DPL and transferred its ownership interests in the assets and liabilities of MVE, Inc. to Plaza Building Inc., which is another wholly-owned subsidiary of DPL, via dividends-in-kind and a repayment of inter-company debt. Total assets and liabilities transferred were $470.1 million and $19.0 million, respectively. 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 $5.7 million in 2001, $6.1 million in 2000, and $12.5 million in 1999. 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(cent) 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(cent) 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 $55.4 million in 2001 and $53.5 million in 2000. 29 Property, Maintenance and Depreciation Property is shown at its original cost. Cost includes direct labor and material and allocable overhead costs. For the majority 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%, 3.5%, and 3.6% for 2001, 2000, and 1999, 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, 2001 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. 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 the Financial Accounting Standard Board's ("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. 30 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 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") that addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets. SFAS No. 143 is effective for the Company as of January 1, 2003. The Company has not yet determined the extent to which its financial condition or results of operations may be affected by the implementation of this accounting standard. 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 No. 71, "Accounting for the Effects of Certain Types of Regulation" to its regulated operations. This accounting standard provides for the deferral of costs authorized for future recovery by regulators. 31 Based on existing regulatory authorization, regulatory assets on the Consolidated Balance Sheet include: At December 31, $ in million 2001 2000 ----------------------------------------------------------------- Regulatory transition costs (a) ............... $ 97.2 $144.8 Income taxes recoverable through future revenues (b) .............................. 39.2 49.4 Other costs (b) ............................... 2.5 1.6 ------ ------ Total ......................................... $138.9 $195.8 ====== ====== (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, at which time the Company's generation business unit will be fully merchant. 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. 32 5. Income Taxes
For the years ended December 31, $ in millions 2001 2000 1999 ------------------------------------------------------------------------------------------------ Computation of tax expense Federal income tax (a)............................................... $139.6 $183.0 $109.7 Increases (decreases) in tax from -- Regulatory assets............................................... -- -- 4.4 Depreciation.................................................... 4.5 6.5 13.1 Investment tax credit amortized................................. (2.3) (6.1) (3.0) Other, net...................................................... (0.4) (0.8) (3.1) ------ ------ ------ Total tax expense........................................... $141.4 $182.6 $121.1 ====== ====== ====== Components of Tax Expense Taxes currently payable.............................................. $146.9 $243.0 $107.2 Deferred taxes-- Regulatory assets............................................... (12.5) (13.3) (5.8) Liberalized depreciation and amortization....................... (5.7) (29.3) 5.8 Fuel and gas costs.............................................. 1.1 (7.1) 9.2 Other........................................................... 13.9 (4.6) 7.7 Deferred investment tax credit, net.................................. (2.3) (6.1) (3.0) ------ ------ ------ Total tax expense........................................... $141.4 $182.6 $121.1 ====== ====== ======
(a) The statutory rate of 35% was applied to pre-tax income. Components of Deferred Tax Assets and Liabilities At December 31, $ in millions 2001 2000 -------------------------------------------------------------------- Non-current Liabilities Depreciation/property basis .................... $(392.8) $(403.8) Income taxes recoverable ....................... (14.4) (17.3) Regulatory assets .............................. (38.6) (50.6) Investment tax credit .......................... 20.7 21.1 Other .......................................... 28.1 20.7 ------- ------- Net non-current liability ................. $(397.0) $(429.9) ======= ======= Net Current Asset .............................. $ 1.3 $ 11.1 ======= ======= 33 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 2001 2000 -------------------------------------------------------------------------- Change in Projected Benefit Obligation -------------------------------------- Benefit obligation, January 1 .......................... $273.7 $272.8 Service cost ........................................... 4.3 5.1 Interest cost .......................................... 17.3 18.9 Amendments ............................................. 0.2 21.1 Special termination benefit (a) ........................ 5.3 -- Curtailment (b) ........................................ -- (3.1) Actuarial (gain) loss .................................. (13.4) (26.6) Benefits paid .......................................... (16.2) (14.5) ------ ------ Benefit obligation, December 31 ........................ 271.2 273.7 ------ ------ Change in Plan Assets --------------------- Fair value of plan assets, January 1 ................... 361.3 421.3 Actual return on plan assets ........................... (63.8) (45.5) Benefits paid .......................................... (16.2) (14.5) ------ ------ Fair value of plan assets, December 31 ................. 281.3 361.3 ------ ------ Plan assets in excess of projected benefit obligation ........................................... 10.1 87.6 Unrecognized actuarial (gain) loss ..................... 44.1 (45.8) Unamortized prior service cost ......................... 18.6 23.2 ------ ------ Net pension assets ..................................... $ 72.8 $ 65.0 ====== ====== Assumptions used in determining the projected benefit obligation were as follows: 2001 2000 1999 ------------------------------- Discount rate for obligations ............... 7.25% 7.25% 6.25% Expected return on plan assets .............. 9.00% 9.00% 7.50% Average salary increases .................... 4.00% 5.00% 5.00% 34 The following table sets forth the components of pension expense (portions of which were capitalized): $ in millions 2001 2000 1999 ---------------------------------------------------------------------------- Expense for Year ---------------- Service cost .................................... $ 4.3 $ 5.1 $ 5.9 Interest cost ................................... 17.3 18.9 16.2 Expected return on plan assets .................. (32.9) (33.9) (25.3) Amortization of unrecognized: Actuarial (gain) loss ......................... (6.6) (5.0) (0.5) Prior service cost ............................ 3.5 4.2 2.1 Transition obligation ......................... -- (2.8) (4.3) ------ ------ ------ Net pension cost ................................ (14.4) (13.5) (5.9) Special termination benefit (a) ................. 5.3 -- -- Curtailment (a) ................................. 1.4 2.1 -- ------ ------ ------ Net pension cost after special termination benefitand curtailment .............. $ (7.7) $(11.4) $ (5.9) ====== ====== ====== (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 2001 2000 ---------------------------------------------------- Change in APBO -------------- Benefit obligation, January 1 ...... $30.8 $32.4 Interest cost ...................... 2.2 2.2 Curtailment (a) .................... -- (0.1) Actuarial (gain) loss .............. 2.6 (1.0) Benefits paid ...................... (2.6) (2.7) ----- ----- Benefit obligation, December 31 .... 33.0 30.8 ----- ----- 35 $ in millions 2001 2000 ------------------------------------------------------------------- Change in Plan Assets --------------------- Fair value of plan assets, January 1 ......... 10.9 10.9 Actual return on plan assets ................. 0.9 1.0 Company contributions ........................ 1.8 1.7 Benefits paid ................................ (2.7) (2.7) ----- ----- Fair value of plan assets, December 31 ....... 10.9 10.9 ----- ----- APBO in excess of plan assets ................ 22.1 19.9 Unamortized transition obligation ............ (3.9) (6.9) Actuarial gain ............................... 17.6 21.8 ----- ----- Accrued postretirement benefit liability ..... $35.8 $34.8 ===== ===== Assumptions used in determining the projected benefit obligation were as follows: 2001 2000 1999 ------------------------------- Discount rate for obligations ................ 7.25% 7.25% 6.25% Expected return on plan assets ............... 7.00% 7.00% 5.70% The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation was 7.0% and 7.5% for 2001 and 2000 , 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 $1.9 million; and a one percentage point decrease would decrease the benefit obligation by $1.7 million. The following table sets forth the components of postretirement benefit expense: $ in millions 2001 2000 1999 ------------------------------------------------------------------------------- Expense for Year ---------------- Interest cost ....................................... $ 2.2 $ 2.2 $ 2.0 Expected return on plan assets ...................... (0.7) (0.7) (0.7) Amortization of unrecognized: Actuarial (gain) loss ............................. (1.6) (2.2) (2.4) Transition obligation ............................. 2.9 2.9 3.0 ----- ----- ----- Postretirement benefit cost ......................... 2.8 2.2 1.9 Curtailment (a) ..................................... -- 0.1 -- ----- ----- ----- Postretirement benefit cost after curtailment ....... $ 2.8 $ 2.3 $ 1.9 ===== ===== ===== (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). 36 7. Preferred Stock $25 par value, 4,000,000 shares authorized, no shares outstanding; and $100 par value, 4,000,000 shares authorized, 228,508 shares without mandatory redemption provisions outstanding. Current Current Par Value Redemption Shares At December 31, 2001 and 2000 Series Rate Price Outstanding ($ in millions) ------------------------------------------------------------------------ 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 2001 2000 ----------------------------------------------------------------------------- First mortgage bonds maturing 2024-2026 8.01% (a) ........ $446.0 $446.0 Pollution control series maturing through 2027 6.43% (a)... 105.6 106.0 ------ ------ 551.6 552.0 Guarantee of Air Quality Development Obligations 6.10% Series Due 2030 ................................ 110.0 110.0 Obligation for capital lease .............................. 5.4 4.9 Unamortized debt discount and premium (net) ............... (0.4) (0.4) ------ ------ Total ................................................ $666.6 $666.5 ====== ====== (a) Weighted average interest rate for 2001 and 2000. The amounts of maturities and mandatory redemptions for first mortgage bonds, notes, and the capital lease are $1.1 million per year in 2002 through 2006. 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 its subsidiaries have $200 million available through revolving credit agreements with a consortium of banks. Facility fees are approximately $0.3 million per year. The primary purpose of the revolving credit facilities is to provide back-up liquidity for the commercial paper program. At December 31, 2001 and 2000, DPL had no outstanding borrowings under these credit agreements. 37 The Company also has $75.0 million available in short-term informal lines of credit. The commitment fees are immaterial. Borrowings at December 31, 2001 and 2000 were zero. The Company had no outstanding commercial paper balances at December 31, 2001 and 2000. 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 represent three-year awards, vest five years from the grant date, and expire ten years from the grant date. At December 31, 2001, there were 767,500 options available for grant. Summarized stock option activity was as follows: 2001 2000 --------------------------------------------------------------------------- Options granted at beginning of year 7,610,000 -- Granted......................................... 127,500 7,610,000 Exercised....................................... -- -- Forfeited....................................... (505,000) -- ---------- ---------- Outstanding at year-end......................... 7,232,500 7,610,000 Exercisable at year-end......................... -- -- Weighted average option prices per share: At beginning of year......................... $ 22.10 $ -- Granted...................................... 27.17 22.10 Exercised.................................... -- -- Forfeited.................................... 24.97 -- Outstanding at year-end...................... 21.99 22.10 Exercisable at year-end...................... $ -- $ -- The weighted-average fair value of options granted was $3.47 and $3.65 per share in 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: 38 2001 2000 -------------------------------------- Volatility 18.5% 18.5% Expected life (years) 5.1 5.1 Dividend yield rate 3.6% 3.5% Risk-free interest rate 4.5% 6.8% The Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25") and related interpretations in accounting for its employee stock options. Under APB 25, compensation expense of $2.3 million was recorded in 2001 and in 2000 for grants issued prior to the measurement date for accounting purposes. If the Company had used a fair-value method of accounting for stock-base compensation cost, reported earnings on common stock for 2001 and 2000 would have been $232.8 and $296.4 million, respectively. The following table reflects information about stock options outstanding at December 31, 2001:
Options Outstanding Options Exercisable ----------------------- ----------------------- Weighted- Average Weighted- Weighted- Contractual Average Average Range of Exercise Number Life Exercise Number Exercise Prices Outstanding (in years) Price Exercisable Price --------------------------------------------------------- ----------------------- $21.00-$29.63 7,232,500 8.2 $21.99 -- --
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, 2001, the Company had $133 million of construction in progress at such facilities. The Company's share of the operating cost of such facilities is included in the Consolidated Statement of Results of Operations, and its share of the investment in the facilities is included in the Consolidated Balance Sheet. 39 The following table presents the Company's undivided ownership interest in such facilities at December 31, 2001:
Company Company Share Investment ---------------------- --------------- Production Gross Plant Ownership Capacity in Service (%) (MW) ($ in millions) -------------------------------------------------------------------------------------------- Production Units: Beckjord Unit 6 ............................ 50.0 210 57 Conesville Unit 4 .......................... 16.5 129 31 East Bend Station .......................... 31.0 186 154 Killen Station ............................. 67.0 418 381 Miami Fort Units 7 & 8 ..................... 36.0 360 129 Stuart Station ............................. 35.0 823 260 Zimmer Station ............................. 28.1 365 996 Transmission (at varying percentages) ........... 86
12. Fair Value of Financial Instruments
At December 31, 2001 2000 Gross Unrealized Gross Unrealized ---------------- ---------------- Fair Fair $ in millions Value Gains Losses Cost Value Gains Losses Cost ------------------------------------------------------------------------------------------------------ Assets Available-for-sale equity securities .................. $ 95.3 $43.9 $(14.4) $ 65.8 $122.9 $58.2 $-- $ 64.7 Held-to-maturity securities: Debt securities (a) ...... 45.8 -- (0.2) 46.0 $ 50.2 0.8 -- $ 49.4 Temporary cash investments -- -- -- -- 11.0 -- -- 11.0 ------ ----- ------ ------ ----- ----- --- ------ Total ................ $141.1 $43.9 $(14.6) $111.8 $184.1 $59.0 $-- $125.1 Liabilities (b) Debt ........................ $678.8 $668.1 $661.8 $662.4
(a) Maturities range from 2002 to 2010. (b) Includes current maturities. Gross realized gains (losses) were $0.9 and $(6.2) million in 2001, $0.1 and $(0.5) million in 2000, and $12.4 and $(1.0) million in 1999, respectively. 40 13. Reconciliation of Net Income to Net Cash Provided by Operating Activities
For the years ended December 31, $ in millions 2001 2000 1999 --------------------------------------------------------------------------------------- Net income ......................................... $235.3 $ 298.8 $192.5 Adjustments: Depreciation and amortization ................. 116.0 130.3 134.0 Noncash extraordinary item, net of tax ........ -- 41.4 -- Gain on sale of natural gas retail distribution operations ................................. -- (182.5) -- Deferred income taxes ......................... (5.5) (60.5) 13.9 Other deferred credits ........................ (49.6) 22.5 3.7 Amortization of regulatory assets, net ........ 46.9 16.3 25.8 Operating expense provisions .................. (0.9) 26.9 (10.3) Accounts receivable ........................... 10.6 (5.4) 12.6 Accounts payable .............................. 24.4 (36.7) 24.8 Accrued taxes payable ......................... (13.5) 63.5 3.3 Inventory ..................................... (15.7) (5.8) 19.3 Other ......................................... (14.8) (23.3) (18.3) --------------------------- Net cash provided by operating activities .......... $333.2 $ 285.5 $401.3 ===========================
14. Business Segment Reporting The Company provides electric services to 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. 41
$ in millions 2001 2000 1999 -------------------------------------------------------------------------------------------- Net revenues: Electric .................................................. $ 838.3 $ 824.0 $ 795.1 Natural Gas ............................................... -- 66.9 85.1 -------- -------- -------- Total .................................................. $ 838.3 $ 890.9 $ 880.2 Operating income: Electric .................................................. $ 415.1 $ 407.7 $ 352.7 Natural Gas ............................................... -- 24.2 27.2 Other (a) ................................................. (2.7) (7.1) 1.1 -------- -------- -------- Total operating income ................................. 412.4 424.8 381.0 Other income (deductions) ................................. 25.9 170.7 14.1 Interest expense .......................................... (62.6) (72.7) (81.5) -------- -------- -------- Income before income taxes, extraordinary item, and cumulative effect of accounting change .................... $ 375.7 $ 522.8 $ 313.6 ======== ======== ======== Depreciation and amortization: Electric .................................................. $ 116.0 $ 122.9 $ 125.9 Natural Gas ............................................... -- 7.4 8.1 -------- -------- -------- Total .................................................. $ 116.0 $ 130.3 $ 134.0 ======== ======== ======== Expenditures - construction additions: Electric .................................................. $ 164.4 $ 117.8 $ 69.9 Natural Gas ............................................... -- 7.1 9.6 -------- -------- -------- Total .................................................. $ 164.4 $ 124.9 $ 79.5 ======== ======== ======== Assets Electric .................................................. $2,546.6 $2,545.7 $2,584.0 Natural Gas ............................................... -- -- 321.7 Unallocated corporate assets .............................. 174.3 205.4 247.8 -------- -------- -------- Total assets ............................................ $2,720.9 $2,751.1 $3,153.5 ======== ======== ========
(a) Includes unallocated corporate items. SELECTED QUARTERLY INFORMATION (Unaudited)
March 31, June 30, September 30, December 31, $ in millions 2001 2000 2001 2000 2001 2000 2001 2000 ----------------------------------------------------------------------------------------------------------------- Utility service revenues ............... $294.7 $361.0 $287.2 $293.9 $351.5 $337.2 $254.8 $301.8 Income before income taxes, extraordinary item, and cumulative effect of accounting change ............ 94.5 88.1 72.3 73.5 136.6 104.4 72.3 256.8 Income before extraordinary item and cumulative effect of accounting change . 56.5 56.1 45.5 47.1 85.5 67.1 46.8 169.9 Net income ............................. 57.5 56.1 45.5 47.1 85.5 25.7 46.8 169.9 Earnings on common stock ............... 57.3 55.9 45.3 46.9 85.2 25.4 46.6 169.7 Cash dividends paid .................... 8.1 -- 57.3 102.5 17.0 87.1 -- 416.8
42 FINANCIAL AND STATISTICAL SUMMARY (Unaudited)
2001 2000 1999 1998 1997 -------------------------------------------------------------------------------------- For the years ended December 31, Utility service revenues (millions) $1,188.2 1,293.9 1,273.3 1,284.2 1,254.4 Earnings on common stock (millions) $ 234.4 297.9 191.6 168.6 171.1 Cash dividends paid (millions) .... $ 82.4 606.4 130.3 238.8 118.5 Electric sales (millions of kWh)-- Residential .................. 4,909 4,816 4,725 4,790 4,788 Commercial ................... 3,618 3,539 3,390 3,518 3,408 Industrial ................... 4,568 4,851 4,876 4,655 4,749 Other retail ................. 1,369 1,371 1,305 1,360 1,330 -------- ------- ------- ------- ------- Total retail ............. 14,464 14,577 14,296 14,323 14,275 Wholesale .................... 3,591 2,946 2,571 3,158 2,334 -------- ------- ------- ------- ------- Total .................... 18,055 17,523 16,867 17,481 16,609 Gas sales (thousands of MCF)-- (a) Residential .................. -- 18,538 24,450 24,877 29,277 Commercial ................... -- 5,838 7,647 7,433 9,567 Industrial ................... -- 2,034 2,246 1,916 2,520 Other ........................ -- 776 1,182 1,699 2,153 Transported gas .............. -- 16,105 20,190 17,788 18,523 ------- ------- ------- ------- Total .................... -- 43,291 55,715 53,713 62,040 At December 31, Total assets (millions) ........... $2,720.9 2,721.5 3,153.5 3,412.4 3,326.8 Long-term debt (millions) ......... $ 666.6 666.5 661.2 885.6 886.0 First mortgage bond ratings-- Standards & Poor's Corporation BBB+ BBB+ AA- AA- AA- Moody's Investors Service .... A2 A2 Aa3 Aa3 Aa3 Number of Preferred Shareholders .. 476 471 509 559 625
(a) The Company completed the sale of its natural gas retail distribution assets and certain liabilities in October 31, 2000. 43 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 index, appearing under Item 14(a)(1) on page 54 present fairly, in all material respects, the financial position of The Dayton Power and Light Company and its subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, 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 index appearing under Item 14(a)(2) on page 54 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 28, 2002 44 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 eleven directors. These directors are also directors of DPL Inc., the holding company of the Company. The directors are to be elected this year to serve until the Annual Meeting of Shareholders in 2003 or until their successors are duly elected and qualified. Should any nominee become unable to accept nomination or election, the Board will vote for the election of such other person as a director as the present directors may recommend in the place of such nominee. The following information regarding the nominees is based on information furnished by them:
Director Since ---------------------------------------------------------------------------------- THOMAS J. DANIS, Age 52 1989 Chairman and Chief Executive Officer, The Danis Companies, Dayton, Ohio, construction, real estate and environmental services. Trustee: Miami Valley Research Park Foundation. JAMES F. DICKE, II, Age 56 1990 President, Crown Equipment Corporation, New Bremen, Ohio, international manufacturer and distributor of electric lift trucks and material handling products. Director: Regional Boys and Girls Clubs of America, Anderson-Cooke, Inc., Dayton Art Institute, Gulf States Paper Co. Chairman: Trinity University Board of Trustees. Secretary: Culver Educational Foundation. PETER H. FORSTER, Age 59 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 63 1991 President and Chief Executive Officer, Ernie Green Industries, Dayton, Ohio, automotive components manufacturer. Director: Pitney Bowes Inc., Eaton Corp.
45
Director Since ---------------------------------------------------------------------------------- JANE G. HALEY, Age 71 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 Miami Valley Economic Development Coalition. ALLEN M. HILL, Age 56 1989 President and Chief Executive Officer, DPL Inc. and The Dayton Power and Light Company. Director: Fifth Third Bancorp, Premier Health Partners. Trustee: Dayton Business Committee, The University of Dayton, Air Force Museum Foundation, Alliance Community Schools. W AUGUST HILLENBRAND, Age 61 1992 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. Company, Hon Industries. Trustee: Batesville Girl Scouts. Trustee Emeritus: Denison University. DAVID R. HOLMES, Age 61 1994 Retired Chairman of the Board and Chief Executive Officer, The Reynolds and Reynolds Company, Dayton, Ohio, information management systems. Director: NCR Corporation, Dayton, Ohio. BURNELL R. ROBERTS, Age 74 1987 Retired Chairman of the Board and Chief Executive Officer, The Mead Corporation, Dayton, Ohio, forest products producer. Principal: Pembroke Associates. Director: Rayonier, Inc., p4A.com Ltd. Trustee: Granum Value Fund.
46
Director Since ---------------------------------------------------------------------------------- GEORGE R. ROBERTS, Age 58 2000 Partner, Kohlberg Kavis Roberts & Co. L.P. and Managing Member of KKR & Co. LLC, New York City, investment company. Director: Accuride Corporation, Amphenol Corporation, Borden, Inc., The Boyds Collection, Ltd., Evenflo Company Inc., IDEX Corporation, KinderCare Learning Center, Inc., KSL Recreation Group, Inc., Owens-Illinois, Inc., PRIMEDIA, Inc., Safeway Inc., Spalding Holdings Corporation. Trustee: Claremont McKenna College, Culver Military Academy. Member: San Francisco Symphony, San Francisco Ballet, Fine Arts Museum. SCOTT M. STUART, Age 42 2000 Member, KKR & Co. LLC, New York City, investment company. Director: AEP Industries Inc., Borden, Inc., The Boyds Collection, Ltd. Board Member: The Boys Club of New York, Greenwich Country Day School, WNET/Channel 13.
47 EXECUTIVE OFFICERS OF THE REGISTRANT (As of March 1, 2002)
Business Experience, Last Five Years (Positions with Registrant NAME Age Unless Otherwise Indicated) Dates ---------------------- --- --------------------------------- ----------------------- Allen M. Hill 56 President and Chief Executive 4/06/92 - 3/01/02 Officer, DPL Inc. and the Company President and Chief Executive 1/01/97 - 3/01/02 Officer, DPL Inc. Stephen F. Koziar, Jr. 57 Group Vice President and 1/31/95 - 3/01/02 Secretary, DPL Inc. and the Company Elizabeth M. McCarthy 42 Group Vice President and Chief 9/26/00 - 3/01/02 Financial Officer, DPL Inc. and the Company Vice President and Chief 4/01/00 - 9/26/00 Accounting Officer, DPL Inc. and the Company Partner, PricewaterhouseCoopers 7/01/94 - 3/31/00 LLP, New York, NY Arthur G. Meyer 51 Vice President, Legal and 11/21/97 - 3/01/02 Corporate Affairs Director, Corporate Relations 5/14/96 - 11/21/97 Bryce W. Nickel 45 Assistant Vice President 1/01/94 - 3/01/02 H. Ted Santo 51 Group Vice President 12/08/92 - 3/01/02 Patricia K. Swanke 42 Vice President, Operations 9/29/99 - 3/01/02 Managing Director 9/08/96 - 9/29/99
48 Item 11 - Executive Compensation -------------------------------------------------------------------------------- COMPENSATION OF DIRECTORS Directors of the Company who are not employees receive an annual award of 1,500 common shares 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 are 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. 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 $600,000 (as well as such bonuses, if any, as may be determined by the Compensation and Management Review Committee in its discretion) and is eligible to receive grants of stock options under the DPL Inc. Stock Option Plan. As Chairman, Mr. Forster is responsible for the long-term strategic planning of the Company, the oversight of financial assets, and the evaluation and recommendations relating to the merger, acquisition and disposition of utility assets. Mr. Forster participates in an incentive program for individuals managing financial assets. 49 EXECUTIVE OFFICER COMPENSATION Summary Compensation Table Set forth below is certain information concerning the compensation of the Chief Executive Officer and each of the other four most highly compensated executive officers of DPL Inc. and the Company, for the last three fiscal years, for services rendered in all capacities.
-------------------------------------------- Long Term Compensation -------------------------------------------- Annual Securities Compensation Underlying LTIP All Other --------------------------- ---- ------------------- ----------- Name and Principal Salary Bonus (1) Options (2) Payouts (3) Compensation (4) ---- ----------- Position Year ($) ($) (#) ($) ($) --------------------------- ---- ------- --------- ----------- ----------- ---------------- Allen M. Hill 2001 675,000 -- -- -- 1,000 President and Chief 2000 600,000 300,000 1,350,000 2,180,000 1,000 Executive Officer 1999 550,000 462,000 -- 525,000 1,000 Peter H. Forster (5) 2001 600,000 -- -- -- 43,000 Chairman 2000 550,000 300,000 2,400,000 3,312,000 61,000 1999 500,000 250,000 -- 1,130,000 84,000 Judy Wyatt (6) 2001 306,000 -- -- -- 1,000 Group Vice President 2000 294,000 100,000 525,000 500,000 1,000 1999 280,000 180,000 -- -- 1,000 Stephen F. Koziar, Jr. 2001 302,000 -- -- -- 1,000 Group Vice President 2000 272,000 100,000 495,000 1,100,000 1,000 And Secretary 1999 259,000 166,000 -- 350,000 1,000 Elizabeth M. McCarthy (7) 2001 330,000 -- 125,000 -- 1,000 Group Vice President and 2000 280,000 220,000 250,000 300,000 1,000 Chief Financial Officer
(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 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 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 for 1999 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. Incentives were earned based on net cumulative investment performance of such assets over the four-year period 1996 through 1999. 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. (4) Amounts in this column represent employer matching contributions on behalf of each named executive under the Company Employee Savings Plan made to the DPL Inc. Employee Stock Ownership Plan. 50 (5) 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. (6) Ms. Wyatt retired from the Company effective January, 1, 2002 after 22 years of service. We offer our sincere appreciation to Ms. Wyatt and wish her well in her future endeavors. (7) 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, $100,000 signing bonus subject to forfeiture and severance benefits. Option Grants in Last Fiscal Year The following table sets forth information concerning individual grants of stock options made to the named executive officers during the fiscal year ended December 31, 2001.
Individual Grants --------------------------------------------------------- Number of Securities % of Total Underlying Options Granted Exercise Options to Employees in Price Expiration Grant Date Name Granted (#)(1) Fiscal Year ($/Share) Date Present Value ($)(2) ---- -------------- --------------- --------- ---------- -------------------- Allen M. Hill .......... -- -- -- -- -- Peter H. Forster.......... -- -- -- -- -- Judy Wyatt ........... -- -- -- -- -- Stephen F. Koziar, Jr..... -- -- -- -- -- Elizabeth M. McCarthy..... 125,000 98 27.12 6/19/11 437,500
(1) Options granted pursuant to the DPL Inc. Stock Option Plan on June 19, 2001. These options vest in five cumulative installments of 20% on December 31, 2002, 2003, 2004, 2005 and 2006 and become exercisable on January 1, 2007. (2) The grant date present value was determined using the Black-Scholes pricing model. Significant assumptions used in the model were: expected volatility 18.5%, risk-free rate of return 4.53%, dividend yield 3.64% and time of exercise 5.1 years. 51 Aggregated Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values The following table sets forth information concerning each exercise of stock options during fiscal 2001 by each of the named executive officers and the fiscal year-end value of unexercised options.
Shares Acquired Number of Securities Underlying Value of Unexercised In-the-Money On Value Unexercised Options at Fiscal Options at Fiscal Exercise Realized Year-End (#) Year-End ($)(1) Name (#) ($) ---- -------- -------- ------------------------------------------------------------------- Exercisable Unexercisable Exercisable Unexercisable ----------- ---------------- ----------- ------------- Allen M. Hill ............. -- -- -- 1,350,000 -- 4,158,000 Peter H. Forster .......... -- -- -- 2,400,000 -- 7,392,000 Judy Wyatt ................ -- -- -- 210,000 -- 646,800 Stephen F. Koziar, Jr ..... -- -- -- 495,000 -- 1,524,600 Elizabeth M. McCarthy ..... -- -- -- 375,000 -- 770,000
(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, 2001. Change in Control Agreements DPL Inc. has in place agreements with each of Mr. Hill, 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. 52 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: Total Annual Retirement Benefits for Years of Accredited Service at Age 65 Final Average -------------------------------------- Annual Earnings 10 Years 15 Years 20-30 Years --------------- -------- --------- ----------- $ 200,000 $ 51,500 $ 77,500 $103,000 400,000 108,500 163,000 217,000 600,000 165,500 248,500 331,000 800,000 222,500 334,000 445,000 1,000,000 279,500 419,500 559,000 1,200,000 336,500 505,000 673,000 1,400,000 393,500 590,500 787,000 The years of accredited service for the named executive officers are Mr. Hill -- 32 yrs.; Mr. Koziar -- 32 yrs.; Ms. Wyatt -- 22 yrs. and Ms. McCarthy -- 19 yrs. 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. Participation in the supplemental plan has been terminated for all executive officers and the benefits enumerated above reduced by 21%. The present value of each individual's accrued benefit under the supplemental plan, determined by DPL Inc.'s actuary, was transferred to a deferred payment account. 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. 53 PART IV Item 14 - 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 on page 23, which page is incorporated herein by reference. 2. Financial Statement Schedule ---------------------------- For the three years in the period ended December 31, 2001: Page No. ------- Schedule II - Valuation and qualifying accounts 60 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. 54 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 Exhibit A to the 1986 the Company dated Proxy Statement January 6, 1986...................................................... (File No. 1-2385) 2(b) Copy of Asset Purchase Agreement, dated December 14, 1999 between The Exhibit 2 to Report on Form Dayton Power and Light Company, Indiana Energy, Inc., and 10-Q for the quarter ended Number-3CHK, Inc..................................................... 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 Exhibit 3(b) to Report on January 3, 1991...................................................... 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 Exhibit 4(a) to Report on Company and The Bank of New York, Trustee with all amendments through Form 10-K for the year ended the Twenty-Ninth Supplemental Indenture.............................. December 31, 1985 (File No.1-2385) 4(b) Copy of the Thirtieth Supplemental Indenture dated as of March 1, Exhibit 4(h) to Registration 1982, between the Company and The Bank of New York, Trustee.......... Statement No. 33-53906 4(c) Copy of the Thirty-First Supplemental Indenture dated as of Exhibit 4(h) to Registration November 1, 1982, between the Company and The Bank of New York, Statement Trustee.............................................................. No. 33-56162 4(d) Copy of the Thirty-Second Supplemental Indenture dated as of Exhibit 4(i) to Registration November 1, 1982, between the Company and The Bank of New York, Statement Trustee.............................................................. No. 33-56162 4(e) Copy of the Thirty-Third Supplemental Indenture dated as of December Exhibit 4(e) to Report on 1, 1985, between the Company and The Bank of New York, Trustee....... Form 10-K for the year ended December 31, 1985 (File No.1-2385)
55 4(f) Copy of the Thirty-Fourth Supplemental Indenture dated as of April 1, Exhibit 4 to Report on Form 1986, between the Company and The Bank of New York, Trustee.......... 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 Exhibit 4(h) to Report on 1, 1986, between the Company and The Bank of New York, Trustee....... 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 Exhibit 4(i) to August 15, 1992, between the Company and The Registration Bank of New York, Trustee ........................................... Statement No. 33-53906 4(i) Copy of the Thirty-Seventh Supplemental Indenture dated as of Exhibit 4(j) to November 15, 1992, between the Company and The Bank of New York, Registration Statement Trustee.............................................................. No. 33-56162 4(j) Copy of the Thirty-Eighth Supplemental Indenture dated as of November Exhibit 4(k) to Registration 15, 1992, between the Company and The Bank of New York, Trustee...... Statement No. 33-56162 4(k) Copy of the Thirty-Ninth Supplemental Indenture dated as of January Exhibit 4(k) to Registration 15, 1993, between the Company and The Bank of New York, Trustee...... Statement No. 33-57928 4(l) Copy of the Fortieth Supplemental Indenture dated as of February 15, Exhibit 4(m) to Report on 1993, between the Company and The Bank of New York, Trustee.......... 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 Exhibit 4(m) to Report on 1, 1999, between the Company and The Bank of New York, Trustee....... Form 10-K for the year ended December 31, 1998 (File No.1-2385) 10(a) Copy of Directors' Deferred Stock Compensation Plan amended December Exhibit 10(a) to Report on 31, 2000............................................................. 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, Exhibit 10(b) to Report on 2000................................................................. Form 10-K for the year ended December 31, 2000 (File No.1-2385)
56 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, Exhibit 10(d) to Report on 2000................................................................. 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 Exhibit 10(e) to Report on Officers............................................................ 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) 18 Copy of preferability letter relating to change Exhibit 18 to Report on Form in accounting for unbilled revenues from Price Waterhouse LLP........ 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 on page 61
(b) Reports on Form 8-K ------------------- None. 57 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 March 28, 2002 /s/ Elizabeth M. McCarthy ------------------------------------------------- Elizabeth M. McCarthy Group Vice President and Chief Financial Officer (principal financial officer) March 28, 2002 /s/ Allen M. Hill ------------------------------------------------- Allen M. Hill President and Chief Executive Officer (principal executive officer) 58 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 Director March 28, 2002 ---------------------- (T. J. Danis) Director March 28, 2002 ---------------------- (J. F. Dicke, II) /s/ P. H. Forster Director and Chairman March 28, 2002 ---------------------- (P. H. Forster) /s/ E. Green Director March 28, 2002 ---------------------- (E. Green) /s/ J. G. Haley Director March 28, 2002 ---------------------- (J. G. Haley) /s/ A. M. Hill Director, President and Chief March 26, 2002 ---------------------- Executive Officer (A. M. Hill) Director March 28, 2002 ---------------------- W A. Hillenbrand) /s/ D. R. Holmes Director March 28, 2002 ---------------------- (D. R. Holmes) /s/ B. R. Roberts Director March 28, 2002 ---------------------- (B. R. Roberts) Director March 28, 2002 ---------------------- (G. R. Roberts) Director March 28, 2002 ---------------------- (S. M. Stuart) /s/ E. M. McCarthy Group Vice President and Chief March 28, 2002 ---------------------- Financial Officer (principal financial (E. M. McCarthy) officer) /s/ W. A. Garrett Controller March 28, 2002 ---------------------- (W. A. Garrett) 59 Schedule II The Dayton Power and Light Company VALUATION AND QUALIFYING ACCOUNTS For the years ended December 31, 2001, 2000, and 1999 ($ in thousands)
----------------------------------------------------------------------------------------------------- COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E ----------------------------------------------------------------------------------------------------- Additions --------------- Balance at Charged Balance at Beginning of to Deductions End of Description Period Income Other (1) Period ----------------------------------------------------------------------------------------------------- 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 1999: Deducted from accounts receivable-- Provision for uncollectible accounts... $4,657 $ 5,171 $-- $5,496 $ 4,332
(1) Amounts written off, net of recoveries of accounts previously written off. 60