10-K 1 c75523e10vk.txt FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) (X) Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended DECEMBER 31, 2002 OR ( ) Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from _______to_______ Commission File Number 0-368 OTTER TAIL CORPORATION (Exact name of registrant as specified in its charter) MINNESOTA 41-0462685 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 215 SOUTH CASCADE STREET 56538-0496 BOX 496, FERGUS FALLS, MINNESOTA (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code: 866-410-8780 Securities registered pursuant to Name of each exchange Section 12(b) of the Act: on which registered Title of each class NONE NONE Securities registered pursuant to Section 12(g) of the Act: COMMON SHARES, PAR VALUE $5.00 PER SHARE PREFERRED SHARE PURCHASE RIGHTS CUMULATIVE PREFERRED SHARES, WITHOUT PAR VALUE (Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. (Yes X No _____) Indicate by check mark 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 the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ( ) Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). (Yes X No _____) The aggregate market value of the voting stock held by nonaffiliates on June 28, 2002 was $784,354,838. Indicate the number of shares outstanding of each of the registrant's classes of Common Stock, as of the latest practicable date: 25,593,524 COMMON SHARES ($5 PAR VALUE) AS OF FEBRUARY 28, 2003. Documents Incorporated by Reference: 2002 ANNUAL REPORT TO SHAREHOLDERS-PORTIONS INCORPORATED BY REFERENCE INTO PARTS I AND II PROXY STATEMENT DATED MARCH 6, 2003-PORTIONS INCORPORATED BY REFERENCE INTO PART III PART I Item 1. BUSINESS (a) General Development of Business Otter Tail Corporation (the Company) was incorporated in 1907 under the laws of the State of Minnesota. The Company's executive offices are located at 215 South Cascade Street, Box 496, Fergus Falls, Minnesota 56538-0496 and 3203 32nd Avenue South, P.O. Box 9156, Fargo, North Dakota 58106-9156. Its telephone number is (866) 410-8780. The Company makes available free of charge at its internet website (www.ottertail.com) its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. Information on the Company's website is not deemed to be incorporated by reference into this Annual Report on Form 10-K. In the late 1980s, the Company determined that its core electric business was located in a region of the country where there was little or no growth in the demand for electricity. In order to maintain growth for shareholders, Otter Tail Power Company (as the Company was known) began to explore opportunities for the acquisition and long-term ownership of nonelectric businesses. This strategy has resulted in steady growth over the years. In 2001, the name of the Company was changed to "Otter Tail Corporation" to more accurately represent the broader scope of electric and nonelectric operations and the name "Otter Tail Power Company" was retained for use by the electric utility. In 2002, approximately 57% of the Company's consolidated revenues and approximately 31% of the Company's consolidated net income came from nonelectric operations. The Company's strategy is focused on the growth of its operating companies. The Company's goal is to create value and growth through the acquisition, long-term ownership and decentralized operation of diverse businesses. The Company's electric utility provides a steady base of revenues and earnings as part of this strategy. The following guidelines are considered when reviewing potential acquisition candidates: o Emerging or middle market company; o Proven entrepreneurial management team that will remain after the acquisition; o Products and services intended for commercial rather than retail consumer use; o The potential to provide immediate earnings and future growth; and o Preference for 100% ownership of acquired entities. The Company assesses the performance of its operating companies' return on capital and will consider divesting under-performing operating companies. Otter Tail Corporation and its subsidiaries conducted business in 48 states and 6 Canadian provinces and had approximately 3,111 full-time employees at December 31, 2002. The businesses of the Company have been classified into five segments: Electric, Plastics, Manufacturing, Health Services and Other Business Operations. o Electric (the Utility) includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota 1 and South Dakota under the name Otter Tail Power Company. Electric utility operations have been the Company's primary business since incorporation. o Plastics consists of businesses producing polyvinyl chloride pipe in the Upper Midwest, West, Southwest and South-central regions of the United States. o Manufacturing consists of businesses in the following manufacturing activities: production of waterfront equipment, wind towers, frame-straightening equipment and accessories for the auto repair industry, custom plastic pallets, material and handling trays and horticultural containers; fabrication of steel products; contract machining; and metal parts stamping and fabrication. These businesses are located primarily in the Upper Midwest and Utah. o Health Services consists of businesses involved in the sale of diagnostic medical equipment, supplies and accessories. These businesses also provide service maintenance, mobile and fixed-based diagnostic services, portable X-ray imaging and interim rental of diagnostic medical imaging equipment to various medical institutions located in 40 states. o Other Business Operations consists of businesses in electrical and telephone construction contracting, transportation, telecommunications, entertainment and energy services and natural gas marketing as well as the portion of corporate administrative and general expenses that are not allocated to other segments. These businesses operate primarily in the Upper Midwest, except for the transportation company which operates in 48 states and 6 Canadian provinces. The Company's electric operations, including wholesales power sales, are operated as a division of Otter Tail Corporation, and the Company's energy services and natural gas marketing operations are operated as indirect subsidiaries of Otter Tail Corporation. Substantially all the other businesses are owned by the Company's wholly owned subsidiary, Varistar Corporation (Varistar). The Company continues to investigate acquisitions of additional nonelectric businesses and expects continued growth in this area. The following acquisitions were completed during 2002: o On May 1, 2002 the Company acquired the stock of Computed Imaging Services, Inc. (CIS) of Houston, Texas for 158,257 shares of Otter Tail Corporation common stock and approximately $1.2 million in cash. CIS provides computed tomography and magnetic resonance imaging mobile services, interim rental, and sales and service of new, used and refurbished diagnostic imaging equipment to hospitals and other healthcare facilities in the south central United States. The acquisition of CIS allows the Company to expand its existing Health Services operations into another region of the country. CIS annual revenues were approximately $5.9 million in 2001. o On May 28, 2002 the Company acquired the stock of ShoreMaster, Inc. of Fergus Falls, Minnesota for 303,124 shares of the Company's common stock and $2.3 million in cash. ShoreMaster is a leading manufacturer of waterfront equipment ranging from residential-use boatlifts and docks to commercial marina systems. The acquisition of ShoreMaster is expected to provide diversification and growth opportunities for the Company's Manufacturing segment. ShoreMaster's annual revenues were approximately $20 million in 2001. 2 o On October 1, 2002 the Company acquired the stock of Galva Foam Marine Industries, Inc. of Camdenton, Missouri for 256,940 shares of the Company's common stock and approximately $1.0 million in cash. Galva Foam is a leading manufacturer of waterfront equipment ranging from residential boatlifts and docks to commercial marina systems. The acquisition of Galva Foam, in combination with the ShoreMaster acquisition, will expand the market reach of the Company's waterfront manufacturing product line nationwide with both saltwater and freshwater products. Galva Foam had annual revenues of approximately $13 million in 2001. o In 2002, the Company also acquired two other businesses, neither of which was individually material, one in energy management services and the other in health services. The total purchase price for these businesses was approximately $2 million in cash. For a discussion of the Company's results of operations, see "Management's Discussion and Analysis of Financial Condition and Results of Operations," which is incorporated by reference to pages 18 through 30 of the Company's 2002 Annual Report to Shareholders, filed as an Exhibit hereto. (b) Financial Information About Industry Segments The Company is engaged in businesses that have been classified into five segments: Electric, Plastics, Manufacturing, Health Services and Other Business Operations. Financial information about the Company's segments is incorporated by reference to note 2 of "Notes to Consolidated Financial Statements" on pages 38 through 49 of the Company's 2002 Annual Report to Shareholders, filed as an Exhibit hereto. (c) Narrative Description of Business ELECTRIC General The Utility, which conducts business under the name of Otter Tail Power Company, provides electricity to more than 127,000 customers in a 50,000 square mile area of Minnesota, North Dakota and South Dakota. The Company derived 43% of its consolidated operating revenues from the Electric segment in 2002, 47% in 2001 and 45% in 2000. In 2002, approximately 50.5% of retail electric revenues came from Minnesota, 41.2% from North Dakota and 8.3% from South Dakota compared to 50.9% from Minnesota, 41.2% from North Dakota and 7.9% from South Dakota for 2001. The territory served by the Utility is predominantly agricultural, including a part of the Red River Valley. Although there are relatively few large customers, sales to commercial and industrial customers are significant. By customer category, 29.1% of 2002 electric revenue was derived from commercial customers, 25.0% from residential customers, 15.8% from industrial customers and 30.1% from other sources, including municipalities, farms and wholesale sales. For 2001, electric revenue by category was 26.6% from commercial customers, 23.4% from residential, 15.4% from industrial and 34.6% from other sources. Wholesale electric energy sales increased from 44.0% of total kwh sales in 2001 to 45.2% of total kwh sales in 2002. While wholesale electric energy kwh sales grew 7.8% between the years, revenue per kwh decreased by 22.5% resulting in a reduction of wholesale energy gross margins. Activity in the short-term energy market is subject to change based on a number of factors and it is difficult to predict the quantity of wholesale power sales or prices for wholesale power in the future. However, the Company expects that market conditions for wholesale power transactions in 2003 will be similar to the conditions that existed in 2002. 3 The aggregate population of the Utility's retail electric service area is approximately 230,000. In this service area of 423 communities and adjacent rural areas and farms, approximately 130,900 people live in communities having a population of more than 1,000, according to the 2000 census. The only communities served which have a population in excess of 10,000 are Jamestown, North Dakota (15,527); Fergus Falls, Minnesota (13,471); and Bemidji, Minnesota (11,917). As of December 31, 2002 the Utility served 127,157 customers. This is an increase of 539 customers from December 31, 2001. Capability and Demand At December 31, 2002 the Utility had base load net plant capability totaling 563,258 kw, consisting of 253,508 kw from the jointly-owned Big Stone Plant (constituting the Utility's 53.9% share of the plant's total capability), 154,350 kw from the Hoot Lake Plant (owned solely by the Utility), 149,450 kw from the jointly-owned Coyote Station (constituting the Utility's 35% share of the station's total capability), and, under contract, 5,950 kw from a co-generation plant near Bemidji, Minnesota. In addition to its base load capability, the Utility has combustion turbine and small diesel units, used chiefly for peaking and standby purposes, with a total capability of 92,855 kw, and hydroelectric capability of 4,336 kw. During 2002, the Utility generated about 78% of its retail kwh sales and purchased the balance. The Utility has arrangements to help meet its future base load requirements and continues to investigate other means for meeting such requirements. The Utility has under construction a gas-fired combustion turbine expected to be operational by June 1, 2003. The unit will have a total capability between 40,000 and 50,000 kw. The Utility has an agreement with another utility for the annual exchange of 75,000 kw of seasonal capacity which runs through October 2004. The Utility has an agreement to purchase 50,000 kw of year-round capacity which extends through April 30, 2005 and another agreement to purchase 50,000 kw of year-round capacity through April 30, 2010 from another utility. The Utility had a seasonal capacity agreement to purchase 50,000 kw for the summer 2002. The Utility has a direct control load management system which provides some flexibility to the Utility to effect reductions of peak load. The Utility, in addition, offers rates to customers which encourage off-peak usage. The Utility traditionally experiences its peak system demand during the winter season. For the year ended December 31, 2002, the Utility experienced a system peak demand of 640,220 kw on February 4, 2002. The highest sixty-minute peak demand ever was 642,826 kw on December 14, 2000. The Utility's capability of meeting system demand at the time of the peak in February 2002, including power purchase agreements, its own generating capacity and reserve requirements computed in accordance with accepted industry practice, amounted to 843,969 kw. The Utility's additional capacity available under power purchase contracts (as described above), combined with generating capability and load management control capabilities, is expected to meet 2003 system demand, including industry reserve requirements. Fuel Supply Coal is the principal fuel burned at the Big Stone, Coyote and Hoot Lake generating plants. Coyote, a mine-mouth facility, burns North Dakota lignite coal. Hoot Lake and Big Stone plants burn western subbituminous coal. 4 The following table shows the sources of energy used to generate the Utility's net output of electricity for 2002 and 2001:
2002 2001 ------------------------- ------------------------ Net Kilowatt % of Total Net Kilowatt % of Total Hours Kilowatt Hours Kilowatt Generated Hour Generated Hour Sources (Thousands) Generated (Thousands) Generated ------- ------------ ---------- ------------ ---------- Subbituminous Coal..... 2,459,046 69.3% 2,663,298 70.7% Lignite Coal........... 1,063,942 30.0 1,075,545 28.6 Hydro.................. 24,220 .7 23,531 .6 Oil.................... 1,205 .0 2,891 .1 --------- ----- --------- ----- Total.................. 3,548,413 100.0% 3,765,265 100.0% ========= ===== ========= =====
The Utility has a primary coal supply agreement with RAG Coal West, Inc. for the supply of Wyoming subbituminous coal to Big Stone Plant for 2003-2004. Purchases are made for the supply of subbituminous coal for the Hoot Lake Plant under a contract with Kennecott Coal Sales Company expiring June 30, 2004. A lignite coal contract with Dakota Westmoreland Corporation for the Coyote Station expires in 2016, with a 15-year renewal option subject to certain contingencies. It is the Utility's practice to maintain minimum 30-day inventory (at full output) of coal at the Big Stone Plant, a 20-day inventory at the Coyote Station and a 10-day inventory at the Hoot Lake Plant. Railroad transportation services to the Big Stone Plant are being provided under a common carrier rate by the Burlington Northern and Santa Fe Railroad Co. The Company has filed a complaint in regard to this rate with the Surface Transportation Board requesting the Board set a competitive rate. The Surface Transportation Board is not likely to act on this complaint until late in 2004. The Company would expect the outcome of the proceeding to have a favorable impact on its fuel costs for Big Stone Plant. An agreement is in place with the Burlington Northern and Santa Fe Railroad for Hoot Lake Plant which expires in mid-2004. No coal transportation agreement is needed for the Coyote Station due to its location next to a coal mine. The average cost of coal consumed (including handling charges to the plant sites) per million BTU for each of the three years 2002, 2001 and 2000 was $1.125, $1.014 and $.994, respectively. The Utility is permitted by the State of South Dakota to burn some alternative fuels, including tire derived fuel, at the Big Stone Plant. The quantity of alternative fuel burned at the Big Stone Plant is insignificant when compared to the total annual coal consumption at the Big Stone Plant. General Regulation The Utility is subject to regulation of rates and other matters in each of the three states in which it operates and by the federal government for certain interstate operations. A breakdown of electric rate regulation by each jurisdiction is as follows: 5
2002 2001 ----------------- ------------------- % of % of % of % of Electric kwh Electric kwh Rates Regulation Revenues Sales Revenues Sales ----- ---------- -------- -------- -------- -------- MN retail sales MN Public Utilities Commission 35.8% 28.3% 33.8% 29.3% ND retail sales ND Public Service Commission 29.2 21.9 27.4 22.4 SD retail sales SD Public Utilities Commission 5.8 4.5 5.3 4.3 Transmission & Federal Energy sales for resale Regulatory Commission 29.2 45.3 33.5 44.0 ----- ----- ----- ----- 100.0% 100.0% 100.0% 100.0% ===== ===== ===== =====
The Utility operates under approved retail electric tariffs in all three states it serves. The Utility has an obligation to serve any customer requesting service within its assigned service territory. Accordingly, the Utility has designed its electric system to provide continuous service at time of peak usage. The pattern of electric usage can vary dramatically during a 24 hour period and from season to season. The Utility's tariffs provide for continuous electric service and are designed to cover the costs of service during peak times. To the extent that peak usage can be reduced or shifted to periods of lower usage, the cost to serve all customers is reduced. In order to shift usage from peak times, the Utility has approved tariffs in all three states for lower rates for residential demand control and controlled service, in Minnesota and North Dakota for real-time pricing, and in North Dakota and South Dakota for bulk interruptible rates. Each of these special rates is designed to improve efficient use of the Utility facilities, while encouraging use of cost-effective electricity instead of other fuels and giving customers more control over the size of their electric bill. In all three states, the Utility has approved tariffs which allow qualifying customers to release and sell energy back to the Utility when wholesale energy prices make such transactions desirable. The majority of the Utility's electric retail rate schedules now in effect provide for adjustments in rates based on the cost of fuel delivered to the Utility's generating plants, as well as for adjustments based on the cost of electric energy purchased by the Company. Such adjustments are presently based on a two-month moving average in Minnesota and under FERC, a three-month moving average in South Dakota and a four-month moving average in North Dakota. These adjustments are applied to the next billing after becoming applicable. The following summarizes the material regulations of each jurisdiction applicable to the Utility's electric operations, as well as the specific electric rate proceedings during the last three years with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the Federal Energy Regulatory Commission (FERC). The Company's nonelectric businesses are not subject to direct regulation by any of these agencies. Minnesota: Under the Minnesota Public Utilities Act, the Utility is subject to the jurisdiction of the MPUC with respect to rates, issuance of securities, depreciation rates, public utility services, construction of major utility facilities, establishment of exclusive assigned service areas, contracts and arrangements with subsidiaries and other affiliated interests, and other matters. The MPUC has the authority to assess the need for large energy facilities and to issue or deny certificates of need, after public hearings, within six months of an application to construct such a facility. The Utility has not had a significant rate proceeding before the MPUC since July 1987. 6 The Department of Commerce (DOC) is responsible for investigating all matters subject to the jurisdiction of the DOC or the MPUC, and for the enforcement of MPUC orders. Among other things, the DOC is authorized to collect and analyze data on energy and the consumption of energy, develop recommendations as to energy policies for the governor and the legislature of Minnesota and evaluate policies governing the establishment of rates and prices for energy as related to energy conservation. The DOC acts as a state advocate in matters heard before the MPUC. The DOC also has the power, in the event of energy shortage or for a long-term basis, to prepare and adopt regulations to conserve and allocate energy. Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state's energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota. The DOC may require the utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such DOC orders are appealable to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. Since 1995, the Utility has recovered demand-side management related costs not included in base rates under Minnesota's Conservation Improvement Programs through the use of an annual recovery mechanism approved by the MPUC. The MPUC requires the submission of a 15-year advance integrated resource plan by utilities serving at least 10,000 customers, either directly or indirectly, and having at least 100 megawatts of load. The MPUC's findings and orders with respect to these submissions are binding for jurisdictional utilities. Typically, the filings are submitted every two years. The Utility's most recent plan was submitted to the MPUC in 2002 and was approved early in 2003. The MPUC also granted the Utility a one-year waiver in submitting its next integrated resource plan, which will be completed in 2005. The MPUC requires the annual filing of a capital structure petition. In this filing the MPUC reviews and approves the capital structure for the Company. Once the petition is approved, the Company may issue securities without further petition or approval, provided the issuance is consistent with the purposes and amounts set forth in the approved capital structure petition. The Company's current capital structure petition is in effect until March 31, 2003. The Company filed its capital structure petition for 2003 on January 31, 2003 and is awaiting action from the MPUC. The Minnesota legislature has enacted a statute that favors conservation over the addition of new resources. In addition, it has mandated the use of renewable resources where new supplies are needed, unless the utility proves that a renewable energy facility is not in the public interest. It has effectively prohibited the building of new nuclear facilities. An existing environmental externality law requires the MPUC, to the extent practicable, to quantify the environmental costs of each type of generation, and to use such monetized values in evaluating resource plans. The MPUC must disallow any nonrenewable rate base additions (whether within or outside of the state) or any rate recovery therefrom, and may not approve any nonrenewable energy facility in an integrated resource plan, unless the utility proves that a renewable energy facility is not in the public interest. The state has prioritized the acceptability of new generation with wind and solar ranked first and coal and nuclear ranked fifth, the lowest ranking. Pursuant to the Minnesota Power Plant Siting Act, the Minnesota Environmental Quality Board (EQB) has been granted the authority to regulate the siting in Minnesota of large electric power generating facilities in an orderly manner compatible with environmental preservation and the efficient use of resources. To that end, the EQB is empowered, after study, evaluation and 7 hearings, to select or designate sites in Minnesota for new electric power generating plants (50,000 kw or more) and routes for transmission lines (100 kv or more) and to certify such sites and routes as to environmental compatibility. The Minnesota Legislature enacted the Minnesota Energy Security and Reliability Act in 2001. Its primary focus was to streamline the siting and routing processes for the construction of new electric generation and transmission projects. The bill also added to utility requirements for renewable energy and energy conservation. North Dakota: The Utility is subject to the jurisdiction of the NDPSC with respect to rates, services, certain issuances of securities and other matters. The NDPSC periodically performs audits of gas and electric utilities over which it has rate setting jurisdiction to determine the reasonableness of overall rate levels. In the past, these audits have occasionally resulted in settlement agreements adjusting rate levels for the Utility. The North Dakota Energy Conversion and Transmission Facility Siting Act grants the NDPSC the authority to approve sites in North Dakota for large electric generating facilities and high voltage transmission lines. This Act is similar to the Minnesota Power Plant Siting Act described above and applies to proposed new electric power generating plants of 50,000 kw or more and proposed new transmission lines of more than 115 kv. The Utility is required to submit a ten-year plan to the NDPSC annually. On December 29, 2000 the NDPSC approved a performance-based ratemaking (PBR) plan that links allowed earnings in North Dakota to seven performance standards in the areas of price, electric service reliability, customer satisfaction and employee safety. The PBR plan is effective for 2001 through 2005, unless suspended or terminated by the NDPSC or the Utility. This PBR plan provides the opportunity for the Utility to raise its allowed rate of return and share income with customers when earnings exceed the allowed return. During 2001, the Utility achieved a rate of return on equity that exceeded targets under the plan, resulting in a sharing of the income between shareholders and customers in the form of a $662,300 refund to North Dakota retail electric customers in 2002. The Utility's 2002 rate of return is expected to be within the allowable range defined in the plan. The NDPSC reserves the right to review the issuance of stocks, bonds, notes and other evidence of indebtedness of a public utility. However, the issuance by a public utility of securities registered with the Securities and Exchange Commission is expressly exempted from review by the NDPSC under North Dakota state law. South Dakota: The South Dakota Public Utilities Act subjects the Utility to the jurisdiction of the SDPUC with respect to rates, public utility services, establishment of assigned service areas and other matters. The Utility is not currently subject to the jurisdiction of the SDPUC with respect to the issuance of securities. Under the South Dakota Energy Facility Permit Act, the SDPUC has the authority to approve sites in South Dakota for large energy conversion facilities (100,000 kw or more) and transmission lines of 115 kv or more. There have been no significant rate proceedings in South Dakota since November 1987. FERC: Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935, as amended (FPA). The FERC is an independent agency which has jurisdiction over rates for electricity sales for resale, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one-day suspension period, subject to ultimate approval by the FERC. The Utility is a member of the Mid-Continent Area Power Pool (MAPP), which operates in parts of eight states in the Upper Midwest and in three provinces in Canada. Power pool sales are conducted 8 continuously through MAPP in accordance with schedules filed by MAPP with the FERC. Additional MAPP functions include a regional reliability council that maintains generation reserve sharing requirements. The Utility agreed in October 2001 to join the Midwest Independent System Operator (MISO) regional transmission organization (RTO) pursuant to FERC Order No. 2000. In December 2001, the MISO received FERC approval as a regional transmission organization. FERC's view is that the MISO will benefit the public interest by enhancing the reliability of the Midwest electric grid and facilitating and enhancing wholesale competition. The MISO covers a broad region containing all or parts of 20 states and one Canadian province. The MISO began operational control of the Utility's transmission facilities above 100 kv on February 1, 2002, but the Utility continues to own and maintain its transmission assets. As the transmission provider and security coordinator for the region, the MISO offers available capacity, accepts schedules and provides settlement for transmission services. In July 2002, the FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design (SMD). Its purpose is to insure standard commercial rules for the operation of competitive markets for electricity. The SMD NOPR calls for markets to be operational across the United States by the end of 2004. The MISO, with strong FERC encouragement, has established the end of 2003 as a target for MISO markets to be operational within its geographical area of operation. The MISO is working together with the FERC on this process and has filed proposed energy market rules with FERC for day-ahead and real-time energy markets and financial transmission rights and has requested assurances from FERC that all start-up costs will be recoverable for market participants. As the Utility transitions to the full operation of the MISO there could be short-term negative impacts on wholesale power transactions. Other: The Utility is subject to various federal and state laws, including the Federal Public Utility Regulatory Policies Act and the Energy Policy Act of 1992, which are intended to promote the conservation of energy and the development and use of alternative energy sources. The Utility may also become subject to comprehensive energy legislation currently pending before the United States Congress. The Utility is unable to predict the impact on its operations resulting from future regulatory activities, from future legislation or from future tax that may be imposed on the source or use of energy. Competition, Deregulation and Legislation Electric sales are subject to competition in some areas from municipally owned systems, rural electric cooperatives and, in certain respects, from on-site generators and cogenerators. Electricity also competes with other forms of energy. The degree of competition may vary from time to time depending on relative costs and supplies of other forms of energy. The Utility may also face competition as the restructuring of the electric industry evolves. The Company believes the Utility is well positioned to be successful in a more competitive environment. A comparison of the Utility's electric retail rates to the rates of other investor-owned utilities, cooperatives and municipals in the states the Utility serves indicates that the Utility's rates are competitive. In addition, the Utility would attempt more flexible pricing strategies under an open, competitive environment. Legislative and regulatory activity could affect operations in the future. The Utility cannot predict the timing or substance of any future legislation or regulation. State and federal efforts to restructure the electric utility industry have slowed. The United States Congress ended its 2002 legislative session without passing electric industry restructuring legislation. Congress did consider a comprehensive energy bill, but failed to pass it prior to the November elections. There was no legislative action in 9 2002 regarding electric retail choice in any of the states where the Utility operates and no major electricity legislation is expected in 2003 legislative sessions in those states. The Company does not expect retail competition to come to the States of Minnesota, North Dakota or South Dakota in the foreseeable future. Environmental Regulation Impact of Environmental Laws: The Utility's existing generating plants are subject to stringent federal and state standards and regulations regarding, among other things, air, water and solid waste pollution. The Utility estimates it has expended in the five years ended December 31, 2002, approximately $5.3 million for environmental control facilities. Included in the 2003-2007 construction budget are approximately $2.6 million for environmental equipment for existing and new facilities, including $0.8 million for 2003. Air Quality: Pursuant to the Federal Clean Air Act of 1970 as amended (the Act), the United States Environmental Protection Agency (EPA) has promulgated national primary and secondary standards for certain air pollutants. The primary fuels burned by the Utility's steam generating plants are North Dakota lignite coal and western subbituminous coal. Electrostatic precipitators have been installed at the principal units at the Hoot Lake Plant. A fabric filter to collect particulates from stack gases has been installed on a smaller unit at Hoot Lake Plant. As a result, the units at the Hoot Lake Plant currently meet all presently applicable federal and state air quality and emission standards. The Utility improved the fine particulate emissions control at Big Stone Plant by replacing a major portion of the plant's electrostatic precipitator in the third quarter of 2002. The replacement technology is an Advanced Hybrid technology that was installed as part of a demonstration project co-funded by the Department of Energy's National Energy Technology Laboratory Power Plant Improvement Initiative. The technology is designed to capture at least 99.99% of the fly ash particulates emitted from the boiler. Initial test data demonstrates the emissions design parameters were met. However, the Utility will continue to investigate and assess the operational performance of the unit as well as options to improve the Advanced Hybrid's balance-of-plant impacts as part of its on-going effort to refine the demonstration technology. For the $13.4 million project, the Energy Department's share is approximately $6.5 million, the Utility's share is approximately $2.9 million and the remaining portion was funded by the Big Stone Plant co-owners and other industry participants. The Big Stone Plant is currently operating within all presently applicable federal and state air quality and emission standards. The Coyote Station is equipped with sulfur dioxide removal equipment. The removal equipment--referred to as a dry scrubber--consists of a spray dryer, followed by a fabric filter, and is designed to desulfurize hot gases from the stack. The fabric filter collects spray dryer residue along with the fly ash. The Coyote Station is currently operating within all presently applicable federal and state air quality and emission standards. The Act, in addressing acid deposition, imposed requirements on power plants in an effort to reduce national emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx). The national SO2 emission reduction goals are achieved through a market-based system under which power plants are allocated "emissions allowances" that will require plants to either reduce their emissions or acquire allowances from others to achieve compliance. Each allowance is an authorization to emit one ton of sulfur dioxide. Sulfur dioxide emission requirements are currently being met by all of the Utility's generating facilities without the need to acquire other allowances for compliance. 10 The national NOx emission reduction goals are achieved by imposing mandatory emissions standards on individual sources. All of the Utility's generating facilities met the NOx standards during 2002. Hoot Lake Plant unit 2 is governed by the phase one early opt-in provision until January 1, 2008. The remaining generating units meet the NOx emission regulations that were adopted by the EPA in December 1996. The Act calls for EPA studies of the effects of emissions of listed pollutants by electric steam generating plants. The EPA has completed the studies and sent reports to Congress. The Act required that the EPA make a finding as to whether regulation of emissions of hazardous air pollutants from fossil fuel-fired electric utility generating units is appropriate and necessary. On December 14, 2000 the EPA announced that it affirmatively decided to regulate mercury emissions from electric generating units. The EPA expects to propose regulations by December 2003 and issue final rules by December 2004. Because promulgation of rules by the EPA has not been completed, it is not possible to assess whether, or to what extent, this regulation will impact the Utility. In 1998, the EPA announced its New Source Review Enforcement Initiative targeting coal-fired utilities, petroleum refineries, pulp and paper mills and other industries for alleged violations of EPA's New Source Review rules. These rules require owners or operators that construct new major sources or make major modifications to existing sources to obtain permits and install air pollution control equipment at affected facilities. The EPA is attempting to determine if emission sources violated certain provisions of the Act by making major modifications to their facilities without installing state-of-the-art pollution controls. On January 2, 2001, the Utility received a request from the EPA, pursuant to Section 114(a) of the Act, to provide certain information relative to past operation and capital construction projects at the Big Stone Plant. The Utility has responded to that request and at this time cannot determine what, if any, actions will be taken by the EPA. In December 2002, the EPA issued changes to the existing New Source Review rules. These changes are not expected to result in any significant additional costs to the Utility. The EPA also proposed changes clarifying application of certain sections of the New Source Review rules. The Utility is currently evaluating the proposal. The EPA plans to accept comments on these proposed changes in early 2003 and then undertake a new rule-making process during the next one to two years. The Coyote Station is subject to certain emission limitations under the "Prevention of Significant Deterioration" (PSD) program of the Clean Air Act. The EPA and the North Dakota Department of Health are currently engaged in discussions about the maximum allowable increases of sulfur dioxide, which may result in imposition of a cap on the sulfur dioxide emissions from all the coal-fired steam-electric generating units that are located in North Dakota, including the Coyote Station. If a cap were imposed, it is likely the cap would be set at a level above current actual emission levels. The probable impact of a cap on sulfur dioxide emissions on future operations, if it were imposed, is uncertain. Water Quality: The Federal Water Pollution Control Act Amendments of 1972, and amendments thereto, provide for, among other things, the imposition of effluent limitations to regulate discharges of pollutants, including thermal discharges, into the waters of the United States, and the EPA has established effluent guidelines for the steam electric power generating industry. Discharges must also comply with state water quality standards. The Utility has all federal and state water permits presently necessary for the operation of the Big Stone and Hoot Lake Plants. The water discharge permit for the Coyote Station was renewed in 1998 for a five-year term. The Utility has filed the permit renewal application for Coyote Station and believes that since there are no significant issues with the renewal request, it will receive a renewed permit in due course. The Utility owns five small dams on the Otter Tail River, which are subject to FERC licensing 11 requirements. A license for all five dams was issued on December 5, 1991. Total nameplate rating (manufacturer's expected output) of the five dams is 3,450 kw. Solid Waste: Permits for disposal of ash and other solid wastes have been issued for the Coyote Station and the Big Stone Plant. The Hoot Lake Plant permit was under public notice until January 17, 2003 and the Utility expects that the permit will be issued shortly. The Utility estimates that the current ash disposal site at the Hoot Lake Plant will be filled to capacity within approximately one year. The Utility plans to increase marketing of the ash for construction purposes and to build a new ash disposal site adjacent to the current site within the same permitted area in 2003. An estimate of the engineering costs required to construct a new facility has been completed. On that basis, the Utility believes that the investment required will not have a significant impact on future plant operating costs. At the request of the Minnesota Pollution Control Agency (MPCA), the Utility has an ongoing investigation at its former, closed Hoot Lake Plant ash disposal sites. The MPCA continues to monitor site activities under their Voluntary Investigation and Cleanup Program. In April 2001, the Utility submitted a Remedial Investigation Work Plan to the MPCA describing its plan to further investigate the environmental impact of the closed portion of the Hoot Lake Plant ash disposal site. The MPCA approved the plan, with some suggested modifications, in July 2001. These tasks have been completed. The MPCA also asked that the Utility eliminate a ground water seepage that was originating from one of the disposal areas. Site work relating to that request was completed in November 2001. However, seepage reappeared in a new location in the spring of 2002. The Utility initiated additional studies to further characterize the site and its report was submitted to the MPCA in March 2003 for their review and comment. Although the Utility is still evaluating various options, its preliminary estimate of remediation costs to address the ash disposal site issues over the next three years is not expected to have a material impact on the Company's consolidated results of operations, financial position or cash flows. The EPA has promulgated various solid and hazardous waste regulations and guidelines pursuant to, among other laws, the Resource Conservation and Recovery Act of 1976, the Solid Waste Disposal Act Amendments of 1980 and the Hazardous and Solid Waste Amendments of 1984, which provide for, among other things, the comprehensive control of various solid and hazardous wastes from generation to final disposal. The States of Minnesota, North Dakota and South Dakota have also adopted rules and regulations pertaining to solid and hazardous waste. The total impact on the Utility of the various solid and hazardous waste statutes and regulations enacted by the federal government or the States of Minnesota, North Dakota and South Dakota is not certain at this time. To date, the Utility has incurred no significant costs as a result of these laws. In 1980, the United States enacted the Comprehensive Environmental Response, Compensation and Liability Act, commonly known as the Federal Superfund law, which was reauthorized and amended in 1986. In 1983, Minnesota adopted the Minnesota Environmental Response and Liability Act, commonly known as the Minnesota Superfund law. In 1988, South Dakota enacted the Regulated Substance Discharges Act, commonly known as the South Dakota Superfund law. In 1989, North Dakota enacted the Environmental Emergency Cost Recovery Act. Among other requirements, the federal and state acts establish environmental response funds to pay for remedial actions associated with the release or threatened release of certain regulated substances into the environment. These federal and state Superfund laws also establish liability for cleanup costs and damage to the environment resulting from such release or threatened release of regulated substances. The Minnesota Superfund law also creates liability for personal injury and economic loss under certain circumstances. The Utility is unable to determine the total impact of the Superfund laws on its operations at this time but has not incurred any significant costs to date related to these laws. The Utility is not presently named as a potentially 12 responsible party under the federal or state Superfund laws. Capital Expenditures The Utility is continually expanding, replacing and improving its electric facilities. During 2002, approximately $45.8 million was invested for additions and replacements to its electric utility properties, including $16 million for continuing work on the new gas-fired combustion turbine and $7 million for completion of the Company-owned portion of a large transmission line project in North Dakota. During the five years ended December 31, 2002 gross electric property additions, including construction work in progress, were approximately $146.9 million and gross retirements were approximately $43.0 million. The Utility estimates that during the five-year period 2003-2007 it will invest approximately $146 million for electric construction. The Utility continuously reviews options for increasing its generating capacity. While at this time the Utility has no firm plans for additional base load generating plant construction, the Utility has under construction a gas-fired combustion turbine expected to be operational by June 1, 2003. Most of the costs related to the construction of the gas-fired combustion turbine occurred in 2002. The majority of electric utility expenditures for the five-year period 2003 through 2007 will be for work related to the Utility's production plants and distribution system. Franchises At December 31, 2002 the Utility had franchises to operate as an electric utility in all of the 371 incorporated municipalities that it serves. All franchises are nonexclusive and generally were obtained for 20-year terms, with varying expiration dates. No franchises are required to serve unincorporated communities in any of the three states that the Utility serves. Employees At December 31, 2002 the Utility had approximately 728 full-time employees. A total of 365 employees are represented by local unions of the International Brotherhood of Electrical Workers and are covered by a three-year labor contract expiring November 1, 2005. The Utility has not experienced any strike, work stoppage or strike vote, and considers its present relations with employees to be good. PLASTICS General Plastics consists of businesses producing polyvinyl chloride (PVC) pipe. The Company derived 12% of its consolidated operating revenues from this segment in 2002, 10% in 2001 and 14% in 2000. The following is a brief description of these businesses: Northern Pipe Products, Inc., located in Fargo, ND, manufactures and sells PVC pipe for municipal, rural water, irrigation and other uses in the Upper Midwest region of the United States. Vinyltech Corporation, located in Phoenix, AZ, manufactures and sells PVC pipe for municipal, rural water, irrigation and other uses in the West, Southwest and South-central regions of the United States. Together these companies have the capacity to produce approximately 170 million pounds of PVC pipe annually. 13 Customers The PVC pipe products are marketed through a combination of independent sales representatives, company salespersons and customer service representatives. Customers for the PVC pipe products consist primarily of wholesalers and distributors throughout the Upper Midwest, Southwest and Western United States. Competition The plastic pipe industry is highly competitive, due to a relatively small number of producers, an even smaller number of raw material suppliers and the commodity nature of the product. Because of shipping costs, competition is usually regional in scope, instead of national. Northern Pipe and Vinyltech compete not only against other plastic pipe manufacturers, but also ductile iron, steel, concrete and clay pipe producers. Pricing pressure will continue to affect operating margins in the future. Northern Pipe and Vinyltech intend to continue to compete on the basis of their high quality products, cost-effective production techniques and close customer relations and support. Manufacturing and Resin Supply PVC pipe is manufactured through a process known as extrusion. During the production process, PVC compound (a dry powder-like substance) is introduced into an extrusion machine, where it is heated to a molten state and then forced through a sizing apparatus to produce the pipe. The newly extruded pipe is then pulled through a series of water cooling tanks, marked to identify the type of pipe and cut to finished lengths. Warehouse and outdoor storage facilities are used to store the finished product. Inventory is shipped from storage to customers mainly by common carrier. The PVC resins are acquired in bulk and shipped to point of use by rail car. Over the last ten years, there has been consolidation in PVC resin producers. There are a limited number of third party vendors that supply the PVC resin used by Northern Pipe and Vinyltech. During 2002, seven vendors supplied the resin used, with over 58% of the resin purchased from two main vendors. During 2001 and 2000, two vendors provided approximately 75% of the PVC resin used. The loss of a key vendor, or any interruption or delay in the supply of PVC resin could disrupt the ability of the Plastics segment to manufacture products, cause customers to cancel orders or require incurrence of additional expenses to obtain PVC resin from alternative sources, if such sources were available. Both Northern Pipe and Vinyltech believe they have good relationships with their key raw material vendors. Due to the commodity nature of PVC resin and PVC pipe and the dynamic supply and demand factors worldwide, historically the markets for both PVC resin and PVC pipe have been very cyclical with significant fluctuations in prices and gross margins. Capital Expenditures Capital expenditures in the Plastics segment typically include investments in extrusion machines, land and buildings and management information systems. During 2002, capital expenditures of approximately $6 million were made in the Plastics segment. Expenditures during 2002 included the purchase of land and buildings by Vinyltech that were previously being leased. Total capital expenditures during the five-year period 2003-2007 are estimated to be approximately $14 million. During 2003, Northern Pipe will be opening a new polyethylene (PE) pipe plant in Hampton, IA. This new operation will require approximately $3.5 million in pipe production equipment. Production of PE pipe will be a new product line for the Plastics segment and will allow Northern Pipe to provide 14 its customers with additional product choices. The production process will require using a new type of resin that will be purchased from different vendors than those who provide the PVC resin. The new plant is expected to be producing PE pipe by April 1, 2003. Employees At December 31, 2002 the Plastics segment had approximately 163 full-time employees. MANUFACTURING General Manufacturing consists of businesses in the following manufacturing activities: production of waterfront equipment, wind towers, frame-straightening equipment and accessories for the auto repair industry, custom plastic pallets, material and handling trays and horticultural containers; fabrication of steel products; contract machining; and metal parts stamping and fabrication. During 2002, two acquisitions were completed in this segment. In May, the Company acquired the stock of ShoreMaster, Inc. and in October the Company acquired the stock of Galva Foam Marine Industries, Inc. During 2002, Precision Machine, Inc. was merged into BTD Manufacturing, Inc. The Company derived 20% of its consolidated operating revenues from this segment in 2002, 19% in 2001 and 17% in 2000. The following is a brief description of each of these businesses: BTD Manufacturing, Inc. (BTD), located in Detroit Lakes and Pelican Rapids, MN, is a metal stamping and tool and die manufacturer that provides its services mainly to customers in the Midwest. BTD stamps, fabricates, welds and laser cuts metal components according to manufacturers' specifications primarily for the recreation vehicle, gas fireplace, health and fitness and enclosure industries. Chassis Liner Corporation, located in Alexandria and Lucan, MN, manufactures and markets vehicle frame-straightening equipment and accessories used by the auto repair industry throughout the United States. DMI Industries Inc.(DMI), located in West Fargo, ND, engineers and manufactures towers for the wind energy industry throughout the United States. T.O. Plastics, Inc., located in Minneapolis and Clearwater, MN, and Hampton, SC, manufactures and sells plastic thermoformed products for the horticulture industry throughout the United States. In addition, T.O. Plastics produces products such as clamshell packing, blister packs, returnable pallets and handling trays for shipping and storing odd-shaped or difficult-to-handle parts for other industries. ShoreMaster, Inc., located in Fergus Falls, MN, along with its wholly owned subsidiary, Galva Foam Marine, Inc. located in Camdenton, MO, produce and market residential and commercial waterfront equipment, ranging from boatlifts and docks to full marina systems throughout the United States. St. George Steel Fabrication, Inc., located in St. George and Salt Lake City, UT, fabricates structural steel members for buildings and bridges, ductwork for the power and refining industries, conveyors and hoppers for mining and industrial markets and plate steel products for the wind tower industry, primarily for customers in the Western United States. 15 Competition The various markets in which the Manufacturing segment entities compete are characterized by intense competition. These markets have many established manufacturers with broader product lines, greater distribution capabilities, greater capital resources and larger marketing, research and development staffs and facilities than the Company's manufacturing entities. The Company believes the principal competitive factors in its Manufacturing segment are product performance, quality, price, ease of use, technical innovation, cost effectiveness, customer service and breadth of product line. The Company's manufacturing entities intend to continue to compete on the basis of their high-performance products, innovative technologies, cost-effective manufacturing techniques, close customer relations and support, and their strategy of increasing product offerings. Some of the products sold by the companies in the Manufacturing segment are purchased by companies in the recreational vehicle, wind energy and auto repair markets. A downturn in these markets could have an adverse impact on the financial results of the Company's Manufacturing segment. Legislation The failure of Congress to pass a broad energy bill in 2003 could have an unfavorable impact on the Company's operations that manufacture towers for the wind energy industry. Capital Expenditures Capital expenditures in the Manufacturing segment typically include additional investments in new manufacturing equipment or expenditures to replace worn-out manufacturing equipment. Capital expenditures may also be made in the purchase of land and buildings for plant expansion and investments in management information systems. During 2002, capital expenditures of approximately $15 million were made in the Manufacturing segment. In 2002, structural modifications and new equipment was purchased at BTD in connection with an $8.7 million plant expansion and $3.8 million was spent on a plant expansion at DMI. Total capital expenditures for the Manufacturing segment during the five-year period 2003-2007 are estimated to be approximately $45 million. Employees At December 31, 2002 the Manufacturing segment had approximately 1,060 full-time employees. HEALTH SERVICES General Health Services consists of the DMS Health Group, which includes businesses involved in the sale of diagnostic medical equipment, supplies and accessories. These businesses also provide service maintenance, mobile and fixed-based diagnostic services, portable X-ray imaging and interim rental of diagnostic medical imaging equipment. During 2002, two acquisitions were completed in this segment. In May 2002, the Company acquired the stock of Computed Imaging Service, Inc. On November 1, 2002 the Company acquired the assets and operations of Mobile Diagnostic Services, Inc. 16 The Company derived 13% of its consolidated operating revenues from this segment in 2002, 12% in 2001 and 11% in 2000. The companies comprising the DMS Health Group include: DMS Health Technologies, Inc., located in Fargo, ND, sells, services and refurbishes diagnostic medical imaging equipment and related supplies and accessories. DMS sells radiology equipment primarily manufactured by Philips Medical Systems (Philips), a large multi-national company based in the Netherlands. Philips manufactures fluoroscopic, radiographic and mammography equipment, along with ultrasound, computerized tomography (CT) scanners, magnetic resonance imaging (MRI) scanners and cardiac cath labs. DMS is also a supplier of medical film and related accessories. DMS markets mainly to hospitals, clinics and mobile service companies in North Dakota, South Dakota, Minnesota, Montana and Wyoming. DMS Imaging, Inc., a subsidiary of DMS Health Technologies, Inc. located in Osseo, MN, operates mobile and in-house diagnostic medical imaging equipment, including CT, MRI, positron-emission tomography (PET), nuclear medicine services and other similar radiology services to hospitals, clinics, long-term care facilities and other medical providers located in 40 states. During 2002, regional offices were designated in Houston, TX; Minneapolis, MN; and Sioux Falls, SD. DMS Imaging provides services in four different business units: o DMS Imaging - provides shared diagnostic medical imaging services (primarily mobile) for MRI, CT, nuclear medicine, PET, ultrasound, mammography and bone density analysis. o DMS Interim Solutions - offers interim and rental options for diagnostic imaging services. o DMS MedSource Partners - develops partnerships with healthcare providers to offer dedicated diagnostic imaging services, such as MRI. o DMS Portable X-Ray - delivers portable X-ray, ultrasound and electrocardiogram services to nursing homes and other facilities. Combined, the DMS Health Group covers the three basics of the medical imaging industry: (1) ownership and operation of the imaging equipment for healthcare providers; (2) sale, lease and/or maintenance of medical imaging equipment and related supplies; and (3) scheduling, billing and administrative support of medical imaging services. Regulation The healthcare industry is subject to federal and state regulations relating to licensure, conduct of operation, ownership of facilities, addition of facilities and services and payment of services. The federal Anti-Kickback Act prohibits persons from knowingly and willfully soliciting, receiving, offering or providing remuneration, directly or indirectly, to induce the referral of an individual or the furnishing or arranging for a good or service for which payment may be made under a federal healthcare program such as Medicare or Medicaid. Several states have similar statutes. The term "remuneration" has been broadly interpreted to include anything of value, including, for example, gifts, discounts, credit arrangements, payments of cash, waiver of payments and ownership interests. Penalties for violating the Anti-Kickback Act can include both criminal penalties and civil sanctions. By regulation, the U.S. Department of Health and Human Services has created certain "safe harbors" under the Act. These safe harbor regulations set forth certain provisions, which, if met, assure that healthcare providers will not be subject to liability under the Act. The Ethics and Patient Referral Act of 1989 (the Stark Act) prohibits physician referrals of Medicare and Medicaid patients to an entity providing certain designated health services, including services provided by the Health 17 Services companies. The Stark Act also prohibits an entity from billing for prohibited services. A person who engages in a scheme to violate the Stark Act or a person who presents a claim to Medicare or Medicaid in violation of the Stark Act may be subject to civil fines and possible exclusion from participation in federal healthcare programs. The Health Services companies believe that their operations comply with the Anti-Kickback Act and the Stark Act. However, if the Health Services companies were to engage in conduct in violation of these statutes, the sanction imposed could adversely affect the Company's financial results. The Health Insurance Portability and Accountability Act of 1996 (HIPPA) created federal crimes related to healthcare fraud and to making false statements related to healthcare matters. HIPPA prohibits knowingly and willfully executing a scheme to defraud any healthcare benefit program including a program involving private payers. Further, HIPPA prohibits knowingly and willfully falsifying, concealing or covering up a material fact or making any materially false statement in connection with the delivery of or payment for healthcare benefits or services. A violation of HIPPA is a felony and may result in fines, imprisonment or exclusion from government-sponsored programs such as Medicare and Medicaid. Finally, HIPPA creates federal privacy standards for individually identifiable health information and computer security standards for all health information. These standards become applicable in 2003. The Health Services companies believe that they are in compliance and will be in compliance with the requirements of HIPPA. However, if the Health Services companies were to engage in conduct in violation of these statutes, the sanction imposed could adversely affect the Company's financial results. In some states a certificate of need or similar regulatory approval is required prior to the acquisition of high-cost capital items or services, including diagnostic imaging systems or provisions of diagnostic imaging services by companies or its customers. Certificate of need laws were enacted to contain rising healthcare costs by preventing unnecessary duplication of health resources. Certificate of need regulations may limit or preclude the Health Services companies from providing diagnostic imaging services or systems. Conversely, a repeal of existing certificate of need regulations in states where the Health Services companies have obtained certificates of need could adversely affect their financial performance. The Health Services companies continue to monitor developments in healthcare law and modify their operations from time to time as the business and regulatory environment changes. However, there can be no assurances that the Health Services companies will always be able to modify their operations to address changes in the regulatory environment without any adverse effect to their financial performance. Reimbursement The companies in the Health Services segment derive most of their revenues directly from healthcare providers rather than third-party payers, such as Medicare, Medicaid or private health insurance companies. The Health Services' customers who are healthcare providers receive the majority of their payments from third-party payors. Payments by third-party payors depend upon their policies. Because unfavorable reimbursement policies have limited and may continue to limit the profit margins of hospitals and clinics the Health Services companies bill directly, it may be necessary to lower fees to retain existing customers and attract new ones. Competition The market for selling, servicing and operating diagnostic imaging services and imaging systems is highly competitive. In addition to direct competition from other contract providers, the companies within Health Services compete with free-standing imaging centers and health care providers 18 that have their own diagnostic imaging systems and with equipment manufacturers that sell imaging equipment to healthcare providers for full-time installation. Some of the direct competitors, which provide contract MRI services, have access to greater financial resources than the Health Services companies. In addition, some of Health Services' customers are capable of providing the same services to their patients directly, subject only to their decision to acquire a high-cost diagnostic imaging system, assume the financial and technology risk, and employ the necessary technologies. The companies in the Health Services segment may also experience greater competition in states that currently have certificate of needs laws should these laws be repealed, reducing barriers to entry in that state. The companies within this segment compete against other contract providers on the basis of quality of services, quality and magnetic field strength of imaging systems, relationships with health care providers, knowledge and service quality of technologists, price, availability and reliability. Environmental, Health or Safety Laws Positron emission tomography services and some other imaging services require the use of radioactive material. While this material has a short life and quickly breaks down into inert, or non-radioactive substances, using such materials presents the risk of accidental environmental contamination and physical injury. Federal, state and local regulations govern the storage, use and disposal of radioactive material and waste products. The Company believes that its safety procedures for storing, handling and disposing of these hazardous materials comply with the standards prescribed by law and regulation; however the risk of accidental contamination or injury from those hazardous materials cannot be completely eliminated. The companies in the Health Services segment have not had any material expenses related to environmental, health or safety laws or regulations. Capital Expenditures Capital expenditures in this segment principally relate to the acquisition of diagnostic imaging equipment used in the mobile imaging business. During 2002, capital expenditures of approximately $4 million were made in the Health Services segment. Total capital expenditures during the five-year period 2003-2007 are estimated to be approximately $9 million. Operating leases are also used to finance the acquisition of medical equipment used by Health Services companies. Operating lease payments during the five-year period 2003-2007 are estimated to be $48 million. Employees At December 31, 2002 the Health Services segment had approximately 440 full-time employees. OTHER BUSINESS OPERATIONS General Other Business Operations consists of businesses engaged in electrical and telephone construction contracting, transportation, telecommunications, entertainment and energy services and natural gas marketing as well as the portion of corporate administrative and general expenses that are not allocated to the other segments. The Company derived 12% of its consolidated operating revenues from these businesses in 2002 and 2001 and 13% in 2000. The following is a brief description of each of these businesses: Midwest Construction Services, Inc., is a holding company for three subsidiaries: Aerial Contractors, Inc., located in West Fargo, ND; Moorhead Electric, Inc., located in Moorhead, MN; and Dakota Direct Control, Inc., located in Sioux Falls, SD. Services provided in the Upper Midwest by these companies include electric contracting for 19 industrial, commercial and healthcare sites; installing data network cabling as well as underground copper cable and fiber optics; constructing and repairing overhead and underground electric distribution and transmission lines and substations; and providing building control systems including heating/cooling and security systems. Midwest Information Systems, Inc., headquartered in Parkers Prairie, MN, provides telephone, cable and internet services with over 9,900 access lines for phone, internet and cable television to homes in rural western Minnesota communities through its subsidiaries Midwest Telephone Company, Osakis Telephone Company, Peoples Telephone Company of Big Fork and Data Video Systems, Inc. Otter Tail Energy Services Company, headquartered in Fergus Falls, MN, was established in 1997 to provide unregulated energy-based products and services to commercial, industrial and institutional clients throughout the Upper Midwest. It offers technical and engineering services, energy efficient lighting, water conservation, performance-based service contracting and financial services centered on the management and reduction in demand and consumption of gas, electric and water/sewer utilities. Otter Tail Energy Services Company owns one subsidiary, Otter Tail Energy Management Company, which is a retail marketer of natural gas and energy management services to commercial, industrial and institutional customers in Iowa, South Dakota, North Dakota and Minnesota. E. W. Wylie Corporation (Wylie), located in Fargo, ND, is a contract and common carrier operating a fleet of tractors and trailers in 48 states and 6 Canadian provinces. During 2002, Wylie opened new trucking terminals in Des Moines, IA, and Fort Worth, TX, to expand freight brokerage businesses. Regulation The telephone subsidiaries are subject to the regulatory authority of the MPUC regarding rates and charges for telephone services, as well as other matters. The telephone subsidiaries must keep on file with the MPUC schedules of such rates and charges, and any requests for changes in such rates and charges must be filed for approval by the MPUC. The telephone industry is also subject generally to rules and regulations promulgated by the Federal Communications Commission. The cable television subsidiary is regulated by federal and local authorities. Competition Each of the businesses in Other Business Operations is subject to competition, as well as the effects of general economic conditions in their respective industries. The construction companies in this segment must compete with other construction companies in the Upper Midwest when bidding on new projects. The Company believes the principal competitive factors in the construction segment are price, quality of work and customer services. The trucking industry, in which Wylie competes, is highly competitive. Wylie competes primarily with other short- to medium-haul, flatbed truckload carriers, internal shipping conducted by existing and potential customers and, to a lesser extent, railroads. Competition for the freight transported by Wylie is based primarily on service and efficiency and to a lesser degree, on freight rates. There are other trucking companies that have greater financial resources, operate more equipment or carry a larger volume of freight than Wylie and these companies compete with Wylie for qualified drivers. Capital Expenditures Capital expenditures in this segment typically include investments in additional trucks and flat bed trailers, infrastructure to support the 20 telephone, cable and internet services and construction equipment. During 2002, capital expenditures of approximately $5 million were made in Other Business Operations. Capital expenditures during the five-year period 2003-2007 are estimated to be approximately $26 million for Other Business Operations. Almost all of the $26 million will be used to replace existing equipment with the majority to be invested in the transportation and telecommunication companies. Employees At December 31, 2002 there were approximately 720 full-time employees in Other Business Operations. 84 employees of Moorhead Electric, Inc. are represented by local unions of the International Brotherhood of Electrical Workers and are covered by a two-year labor contract expiring May 31, 2003. Moorhead Electric, Inc. has not experienced any strike, work stoppage or strike vote, and considers its present relations with employees to be good. Forward Looking Information -- Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995 In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 (the Act), the Company has filed cautionary statements identifying important factors that could cause the Company's actual results to differ materially from those discussed in forward-looking statements made by or on behalf of the Company. When used in this Form 10-K and in future filings by the Company with the Securities and Exchange Commission, in the Company's press releases and in oral statements, words such as "may", "will", "expect", "anticipate", "continue", "estimate", "project", "believes" or similar expressions are intended to identify forward-looking statements within the meaning of the Act and are included, along with this statement, for purposes of complying with the safe harbor provision of the Act. Factors that might cause such differences include, but are not limited to, the Company's ongoing involvement in diversification efforts, the timing and scope of deregulation and open competition, growth of electric revenues, impact of the investment performance of the Utility's pension plan, changes in the economy, governmental and regulatory action, weather conditions, fuel and purchased power costs, environmental issues, resin prices, and other factors discussed under "Critical Accounting Policies Involving Significant Estimates" and "Factors Affecting Future Earnings" on pages 24 through 28 of the Company's 2002 Annual Report to Shareholders, filed as an Exhibit hereto. These factors are in addition to any other cautionary statements, written or oral, which may be made or referred to in connection with any such forward-looking statement or contained in any subsequent filings by the Company with the Securities and Exchange Commission. Item 2. PROPERTIES The Coyote Station, which commenced operation in 1981, is a 414,000 kw (nameplate rating) mine-mouth plant located in the lignite coal fields near Beulah, North Dakota and is jointly owned by the Utility, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern Public Service Company. The Utility owns 35% of the plant and on July 1, 1998, became the operating agent of the Coyote Station. The Utility, jointly with Northwestern Public Service Company and Montana-Dakota Utilities Co., owns the 414,000 kw (nameplate rating) Big Stone Plant in northeastern South Dakota which commenced operation in 1975. The Utility is the operating agent of Big Stone Plant and owns 53.9% of the plant. Located near Fergus Falls, Minnesota, the Hoot Lake Plant is comprised of three separate generating units with a combined nameplate rating of 127,000 kw. The oldest Hoot Lake Plant generating unit was constructed in 1948 (7,500 kw nameplate rating) and a subsequent unit was added in 1959 (53,500 kw 21 nameplate rating). A third unit was added in 1964 (66,000 kw nameplate rating) and later modified during 1988 to provide cycling capability, allowing this unit to be more efficiently brought on-line from a standby mode. At December 31, 2002, the Utility's transmission facilities, which are interconnected with lines of other public utilities, consisted of 48 miles of 345 kv lines; 403 miles of 230 kv lines; 727 miles of 115 kv lines; and 4,133 miles of lower voltage lines, principally 41.6 kv. The Utility owns the uprated portion of the 48 miles of the 345 kv line, with Minnkota Power Cooperative retaining title to the original 230 kv construction. In addition to the properties mentioned above, the Company owns and has investments in offices and service buildings. The Company's subsidiaries own facilities and equipment used to manufacture PVC pipe and perform metal stamping, fabricating and contract machining; construction equipment and tools; medical imaging equipment; a fleet of flatbed trucks and trailers; and the infrastructure to maintain approximately 9,900 access lines for phone, internet and cable television in its telecommunication companies. Management of the Company believes the facilities and equipment described above are adequate for the Company's present businesses. All of the common shares of the companies owned by Varistar are pledged to secure indebtedness of Varistar. Item 3. LEGAL PROCEEDINGS Not Applicable. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the three months ended December 31, 2002. Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 2003) Set forth below is a summary of the principal occupations and business experience during the past five years of executive officers of the Company. Except as noted below, each of the executive officers has been employed by the Company for more than five years in an executive or management position either with the Company or its wholly owned subsidiary, Varistar.
DATES ELECTED NAME AND AGE TO OFFICE PRESENT POSITION AND BUSINESS EXPERIENCE ------------- ------------- ---------------------------------------- John D. Erickson (44) 4/8/02 Present: President and Chief Executive Officer 4/9/01 President 4/10/00 Executive Vice President, Chief Financial Officer and Treasurer 10/26/98 Vice President, Finance and Chief Financial Officer Prior to Director, Market 10/26/98 Strategies & Regulation 22
DATES ELECTED NAME AND AGE TO OFFICE PRESENT POSITION AND BUSINESS EXPERIENCE ------------- ------------- ---------------------------------------- George A. Koeck (50) 4/10/00 Present: Corporate Secretary and General Counsel 8/2/99 General Counsel Prior to 8/2/99 Partner, Dorsey & Whitney LLP Lauris N. Molbert (45) 6/10/02 Present: Executive Vice President and Chief Operating Officer 4/9/01 Executive Vice President, Corporate Development and Varistar President and Chief Operating Officer 4/10/00 Vice President, Chief Operating Officer, Varistar; President and Chief Operating Officer, Varistar Prior to President and Chief Operating 4/10/00 Officer, Varistar Kevin G. Moug (43) 4/9/01 Present: Chief Financial Officer and Treasurer Prior to Varistar Chief Financial Officer 4/9/01 and Treasurer
The term of office of each of the officers is one year. Any officer elected may be removed by the vote of the Board of Directors at any time during the term. There are no family relationships between any of the executive officers. PART II Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The information required by this Item is incorporated by reference to the first sentence under "Otter Tail Corporation Stock Listing" on Page 53, to "Selected Consolidated Financial Data" on Page 17 and to "Quarterly Information" on Page 49 of the Company's 2002 Annual Report to Shareholders, filed as an Exhibit hereto. Item 6. SELECTED FINANCIAL DATA The information required by this Item is incorporated by reference to "Selected Consolidated Financial Data" on Page 17 of the Company's 2002 Annual Report to Shareholders, filed as an Exhibit hereto. Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information required by this Item is incorporated by reference to "Management's Discussion and Analysis of Financial Condition and Results of Operations" on Pages 18 through 30 of the Company's 2002 Annual Report to Shareholders, filed as an Exhibit hereto. 23 Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by this Item is incorporated by reference to "Quantitative and Qualitative Disclosures About Market Risk" on Page 30 of the Company's 2002 Annual Report to Shareholders, filed as an Exhibit hereto. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required by this Item is incorporated by reference to "Quarterly Information" on Page 49 and the Company's audited financial statements on Pages 31 through 49 of the Company's 2002 Annual Report to Shareholders excluding "Report of Management" on Page 31, filed as an Exhibit hereto. 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 The information required by this Item regarding Directors is incorporated by reference to the information under "Election of Directors" in the Company's definitive Proxy Statement dated March 6, 2003. The information regarding executive officers is set forth in Item 4A hereto. The information regarding Section 16 reporting is incorporated by reference to the information under "Section 16(a) Beneficial Ownership Reporting Compliance" in the Company's definitive Proxy Statement dated March 6, 2003. Item 11. EXECUTIVE COMPENSATION The information required by this Item is incorporated by reference to the information under "Summary Compensation Table," "Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal Year-End Options/SAR Values," "Pension and Supplemental Retirement Plans," "Severance and Employment Agreements," and "Director Compensation" in the Company's definitive Proxy Statement dated March 6, 2003. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The security ownership information set forth under "Outstanding Voting Shares" and "Management's Security Ownership" in the Company's definitive Proxy Statement dated March 6, 2003 is incorporated herein by reference. 24 EQUITY COMPENSATION PLAN INFORMATION The following table sets forth information as of December 31, 2002 about the Company's common stock that may be issued under all of its equity compensation plans:
Number of securities to be Weighted-average Number of securities remaining issued upon exercise of exercise price of available for future issuance under outstanding options, warrants outstanding options, equity compensation plans (excluding Plan Category and rights warrants and rights securities reflected in column (a)) ------------------------------- ------------------------------ ------------------------ -------------------------------------- (a) (b) (c) Equity compensation plans approved by security holders 1999 Stock Incentive Plan 1,360,721 $24.68 930,602 (1) 1999 Employee Stock Purchase Plan -- N/A 231,761 (2) Equity compensation plans not approved by security holders -- -- -- ------------------------------ ------------------------ -------------------------------------- Total 1,360,721 $24.68 1,162,363 ============================== ======================== ====================================== (1) The 1999 Stock Incentive Plan provides for the issuance of any shares available under the plan in the form of restricted stock, performance awards and other types of stock-based awards, in addition to the granting of options, warrants or stock appreciation rights. (2) Shares are issued based on employees' election to participate in the plan.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. Item 14. CONTROLS AND PROCEDURES (a) Evaluation of Disclosure Controls and Procedures. Under the supervision and with the participation of the Company's management, including the Chief Executive Officer and the Chief Financial Officer, the Company evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-14(c) under the Securities Exchange Act of 1934) as of a date (the "Evaluation Date") within 90 days prior to the filing date of this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures were effective as of the Evaluation Date. (b) Changes in Internal Controls. There were no significant changes in the Company's internal controls or in other factors that could significantly affect those controls subsequent to the date of their most recent evaluation. PART IV Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) List of documents filed: (1) and (2) See Table of Contents on Page 29 hereof. 25 (3) See Exhibit Index on Pages 30 through 35 hereof. Pursuant to Item 601(b)(4)(iii) of Regulation S-K, copies of certain instruments defining the rights of holders of certain long-term debt of the Company are not filed, and in lieu thereof, the Company agrees to furnish copies thereof to the Securities and Exchange Commission upon request. (b) Reports on Form 8-K: None SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. OTTER TAIL CORPORATION By /s/ Kevin G. Moug ------------------------------------- Kevin G. Moug Chief Financial Officer and Treasurer Dated: March 26, 2003 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:
Signature and Title ------------------- John D. Erickson ) President and ) Chief Executive Officer ) (principal executive officer) ) ) Kevin G. Moug ) Chief Financial Officer and Treasurer ) (principal financial and accounting officer) ) ) By /s/ John D. Erickson ) ----------------------------- John C. MacFarlane ) John D. Erickson Chairman of the Board and Director ) Pro Se and Attorney-in-Fact ) Dated March 26, 2003 Thomas M. Brown, Director ) ) Dennis R. Emmen, Director ) ) Maynard D. Helgaas, Director ) ) Arvid R. Liebe, Director ) ) Kenneth L. Nelson, Director ) ) Nathan I. Partain, Director ) ) Gary J. Spies, Director ) ) Robert N. Spolum, Director )
26 CERTIFICATIONS I, John D. Erickson, certify that: 1. I have reviewed this annual report on Form 10-K of Otter Tail Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 26, 2003 /s/ John D. Erickson ------------------------------------- John D. Erickson President and Chief Executive Officer 27 I, Kevin G. Moug, certify that: 1. I have reviewed this annual report on Form 10-K of Otter Tail Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 26, 2003 /s/ Kevin G. Moug ------------------------------------- Kevin G. Moug Chief Financial Officer and Treasurer 28 OTTER TAIL CORPORATION TABLE OF CONTENTS FINANCIAL STATEMENTS, SUPPLEMENTARY FINANCIAL DATA, SUPPLEMENTAL FINANCIAL SCHEDULES INCLUDED IN ANNUAL REPORT (FORM 10-K) FOR THE YEAR ENDED DECEMBER 31, 2002 The following items are included in this annual report by reference to the registrant's Annual Report to Shareholders for the year ended December 31, 2002:
Page in Annual Report to Shareholders ------------ Financial Statements: Independent Auditors' Report.........................................31 Consolidated Balance Sheets, December 31, 2002 and 2001.........32 & 33 Consolidated Statements of Income for the Three Years Ended December 31, 2002..............................................34 Consolidated Statements of Common Shareholders' Equity for the Three Years Ended December 31, 2002..................................35 Consolidated Statements of Cash Flows for the Three Years Ended December 31, 2002..............................................36 Consolidated Statements of Capitalization, December 31, 2002 and 2001 ............................................................37 Notes to Consolidated Financial Statements........................38-49 Selected Consolidated Financial Data for the Five Years Ended December 31, 2002...........................................17 Quarterly Data for the Two Years Ended December 31, 2002 ................................................49
Schedules are omitted because of the absence of the conditions under which they are required, because the amounts are insignificant or because the information required is included in the financial statements or the notes thereto. 29 EXHIBIT INDEX TO ANNUAL REPORT ON FORM 10-K FOR YEAR ENDED DECEMBER 31, 2002
PREVIOUSLY FILED ------------------------------- AS EXHIBIT FILE NO. NO. ------------- -------- 3-A 8-K 3 -- Restated Articles of dated 4/10/01 Incorporation, as amended (including resolutions creating outstanding series of Cumulative Preferred Shares). 3-C 33-46071 4-B -- Bylaws as amended through April 11, 1988. 4-D-1 8-A dated 1 -- Rights Agreement, dated as of 1/28/97 January 28, 1997 (the Rights Agreement), between the Company and Norwest Bank Minnesota, National Association. 4-D-2 8-A/A dated 1 -- Amendment No. 1, dated as of 9/29/98 August 24, 1998, to the Rights Agreement. 4-D-3 10-K for year 4-D-7 -- Note Purchase Agreement dated ended 12/31/01 as of December 1, 2001. 4-D-4 -- First Amendment dated as of December 1, 2002 to Note Purchase Agreement dated as of December 1, 2001. 4-D-5 333-90952 99-A-1 -- Credit Agreement dated as of April 30, 2002. 4-D-6 8-K dated 99-A -- First Amendment dated as of 9/27/02 September 19, 2002 to Credit Agreement dated as of April 30, 2002. 10-A 2-39794 4-C -- Integrated Transmission Agreement dated August 25, 1967, between Cooperative Power Association and the Company. 10-A-1 10-K for year 10-A-1 -- Amendment No. 1, dated as ended 12/31/92 of September 6, 1979, to Integrated Transmission Agreement, dated as of August 25, 1967, between Cooperative Power Association and the Company. 10-A-2 10-K for year 10-A-2 -- Amendment No. 2, dated as of ended 12/31/92 November 19, 1986, to Integrated Transmission Agreement between Cooperative Power Association and the Company.
30
PREVIOUSLY FILED ------------------------------- AS EXHIBIT FILE NO. NO. ------------- -------- 10-C-1 2-55813 5-E -- Contract dated July 1, 1958, between Central Power Electric Corporation, Inc., and the Company. 10-C-2 2-55813 5-E-1 -- Supplement Seven dated November 21, 1973. (Supplements Nos. One through Six have been superseded and are no longer in effect.) 10-C-3 2-55813 5-E-2 -- Amendment No. 1 dated December 19, 1973, to Supplement Seven. 10-C-4 10-K for year 10-C-4 -- Amendment No. 2 dated ended 12/31/91 June 17, 1986, to Supplement Seven. 10-C-5 10-K for year 10-C-5 -- Amendment No. 3 dated ended 12/31/92 June 18, 1992, to Supplement Seven. 10-C-6 10-K for year 10-C-6 -- Amendment No. 4 dated ended 12/31/93 January 18, 1994, to Supplement Seven. 10-D 2-55813 5-F -- Contract dated April 12, 1973, between the Bureau of Reclamation and the Company. 10-E-1 2-55813 5-G -- Contract dated January 8, 1973, between East River Electric Power Cooperative and the Company. 10-E-2 2-62815 5-E-1 -- Supplement One dated February 20, 1978. 10-E-3 10-K for year 10-E-3 -- Supplement Two dated ended 12/31/89 June 10, 1983. 10-E-4 10-K for year 10-E-4 -- Supplement Three dated ended 12/31/90 June 6, 1985. 10-E-5 10-K for year 10-E-5 -- Supplement No. Four, dated ended 12/31/92 as of September 10, 1986. 10-E-6 10-K for year 10-E-6 -- Supplement No. Five, dated ended 12/31/92 as of January 7, 1993. 10-E-7 10-K for year 10-E-7 -- Supplement No. Six, dated ended 12/31/93 as of December 2, 1993.
31
PREVIOUSLY FILED ------------------------------- AS EXHIBIT FILE NO. NO. ------------- -------- 10-F 10-K for year 10-F -- Agreement for Sharing ended 12/31/89 Ownership of Generating Plant by and between the Company, Montana-Dakota Utilities Co., and North- western Public Service Company (dated as of January 7, 1970). 10-F-1 10-K for year 10-F-1 -- Letter of Intent for ended 12/31/89 purchase of share of Big Stone Plant from Northwestern Public Service Company (dated as of May 8, 1984). 10-F-2 10-K for year 10-F-2 -- Supplemental Agreement No. 1 ended 12/31/91 to Agreement for Sharing Ownership of Big Stone Plant (dated as of July 1, 1983). 10-F-3 10-K for year 10-F-3 -- Supplemental Agreement No. 2 ended 12/31/91 to Agreement for Sharing Ownership of Big Stone Plant (dated as of March 1, 1985). 10-F-4 10-K for year 10-F-4 -- Supplemental Agreement No. 3 ended 12/31/91 to Agreement for Sharing Ownership of Big Stone Plant (dated as of March 31, 1986). 10-F-5 10-K for year 10-F-5 -- Amendment I to Letter of ended 12/31/92 Intent dated May 8, 1984, for purchase of share of Big Stone Plant. 10-G 10-Q for quarter 10-B -- Big Stone Plant Coal Agreements ended 09/30/01 by and between the Company, Northwestern Public Service, Montana-Dakota Utilities Co., and RAG Coal West, Inc. (dated as of September 28, 2001). 10-H 2-61043 5-H -- Agreement for Sharing Ownership of Coyote Station Generating Unit No. 1 by and between the Company, Minnkota Power Cooperative, Inc., Montana-Dakota Utilities Co., Northwestern Public Service Company, and Minnesota Power & Light Company (dated as of July 1, 1977). 10-H-1 10-K for year 10-H-1 -- Supplemental Agreement No. ended 12/31/89 One dated as of November 30, 1978, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.
32
PREVIOUSLY FILED ------------------------------- AS EXHIBIT FILE NO. NO. ------------- -------- 10-H-2 10-K for year 10-H-2 -- Supplemental Agreement No. ended 12/31/89 Two dated as of March 1, 1981, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1 and Amendment No. 2 dated March 1, 1981, to Coyote Plant Coal Agreement. 10-H-3 10-K for year 10-H-3 -- Amendment dated as of ended 12/31/89 July 29, 1983, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1. 10-H-4 10-K for year 10-H-4 -- Agreement dated as of Sept. ended 12/31/92 5, 1985, containing Amendment No. 3 to Agreement for Sharing Ownership of Coyote Generating Unit No.1, dated as of July 1, 1977, and Amendment No. 5 to Coyote Plant Coal Agreement, dated as of January 1, 1978. 10-H-5 10-Q for quarter 10-A -- Amendment dated as of ended 9/30/01 June 14, 2001, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1. 10-I 2-63744 5-I -- Coyote Plant Coal Agreement by and between the Company, Minnkota Power Cooperative, Inc., Montana-Dakota Utilities Co., Northwestern Public Service Company, Minnesota Power & Light Company, and Knife River Coal Mining Company (dated as of January 1, 1978). 10-I-1 10-K for year 10-I-1 -- Addendum, dated as of March 10, ended 12/31/92 1980, to Coyote Plant Coal Agreement. 10-I-2 10-K for year 10-I-2 -- Amendment (No. 3), dated as ended 12/31/92 of May 28, 1980, to Coyote Plant Coal Agreement. 10-I-3 10-K for year 10-I-3 -- Fourth Amendment, dated as ended 12/31/92 of August 19, 1985, to Coyote Plant Coal Agreement. 10-I-4 10-Q for quarter 19-A -- Sixth Amendment, dated as of ended 6/30/93 February 17, 1993, to Coyote Plant Coal Agreement. 10-I-5 10-K for year 10-I-5 -- Agreement and Consent to ended 12/31/01 Assignment of the Coyote Plant Coal Agreement.
33
PREVIOUSLY FILED ------------------------------- AS EXHIBIT FILE NO. NO. ------------- -------- 10-K 10-K for year 10-K -- Diversity Exchange Agreement ended 12/31/91 by and between the Company and Northern States Power Company, (dated as of May 21, 1985) and amendment thereto (dated as of August 12, 1985). 10-K-1 10-Q for quarter 10 -- Power Sales Agreement ended 9/30/99 between the Company and Manitoba Hydro Electric Board (dated as of July 1, 1999). 10-L 10-K for year 10-L -- Integrated Transmission ended 12/31/91 Agreement by and between the Company, Missouri Basin Municipal Power Agency and Western Minnesota Municipal Power Agency (dated as of March 31, 1986). 10-L-1 10-K for year 10-L-1 -- Amendment No. 1, dated as ended 12/31/88 of December 28, 1988, to Integrated Transmission Agreement (dated as of March 31, 1986). 10-M 10-K for year 10-M -- Hoot Lake Coal Transportation ended 12/31/99 Agreement by and between the Company and The Burlington Northern and Santa Fe Railway Company (dated as of July 19, 1999). 10-N-1 -- Deferred Compensation Plan for Directors, as amended.* 10-N-2 10-Q for quarter 10-C -- Executive Survivor and ended 3/31/02 Supplemental Retirement Plan, as amended.* 10-N-3 10-K for year 10-N-5 -- Nonqualified Profit Sharing ended 12/31/93 Plan.* 10-N-4 10-Q for quarter 10-B -- Nonqualified Retirement ended 3/31/02 Savings Plan, as amended.* 10-N-5 10-K for year 10-N-6 -- 1999 Employee Stock ended 12/31/98 Purchase Plan. 10-N-6 10-K for year 10-N-7 -- 1999 Stock Incentive Plan.* ended 12/31/98
34
PREVIOUSLY FILED ------------------------------- AS EXHIBIT FILE NO. NO. ------------- -------- 10-O-1 10-Q for quarter 10-A -- Executive Employment Agreement, ended 6/30/02 John Erickson.* 10-O-2 10-Q for quarter 10-B -- Executive Employment Agreement ended 6/30/02 and amendment no. 1, Lauris Molbert.* 10-O-3 10-Q for quarter 10-C -- Executive Employment Agreement, ended 6/30/02 Kevin Moug.* 10-O-4 10-Q for quarter 10-D -- Executive Employment Agreement, ended 6/30/02 George Koeck.* 10-P-1 10-Q for quarter 10-E -- Change in Control Severance ended 6/03/02 Agreement, John Erickson.* 10-P-2 10-Q for quarter 10-F -- Change in Control Severance ended 6/03/02 Agreement, Lauris Molbert.* 10-P-3 10-Q for quarter 10-G -- Change in Control Severance ended 6/03/02 Agreement, Kevin Moug.* 10-P-4 10-Q for quarter 10-H -- Change in Control Severance ended 6/03/02 Agreement, George Koeck.* 13-A -- Portions of 2002 Annual Report to Shareholders incorporated by reference in this Form 10-K. 21-A -- Subsidiaries of Registrant. 23 -- Consent of Deloitte & Touche LLP. 24-A -- Powers of Attorney. 99-A -- Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 as to the Annual Report on Form 10-K for the year ended December 31, 2002, by John D. Erickson, President and Chief Executive Officer, Otter Tail Corporation. 99-B -- Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 as to the Annual Report on Form 10-K for the year ended December 31, 2002, by Kevin G. Moug, Chief Financial Officer and Treasurer, Otter Tail Corporation.
-------- * Management contract or compensatory plan or arrangement required to be filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K. 35