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SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

Commission File Number 0-368

OTTER TAIL CORPORATION

Registrant’s telephone number, including area code: 866-410-8780

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

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. (X)

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 30, 2003 was

Indicate the number of shares outstanding of each of the registrant’s classes of Common Stock, as of the latest practicable date:

Documents Incorporated by Reference:

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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 4334 18th Avenue SW, Suite 200, 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 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 2003, approximately 64% of the Company’s consolidated revenues and approximately 14% 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 strong base of revenues, cash flows and earnings as part of this strategy. The following guidelines are considered when reviewing potential acquisition candidates:

	•		Emerging or middle market company;
	•		Proven entrepreneurial management team that will remain after the acquisition;
	•		Preference for 100% ownership of the acquired company;
	•		Products and services intended for commercial rather than retail consumer use; and
	•		The potential to provide immediate earnings and future growth.

     The Company assesses the performance of its operating companies as follows:

	•		Ability to provide returns on invested capital that exceed the Company’s weighted average cost of capital over the long term; and
	•		Assessment of an operating company’s business and the potential of future earnings growth.

The Company will consider divesting operating companies if they do not meet these criteria over the long term.

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     Otter Tail Corporation and its subsidiaries conducted business in 48 states and 6 Canadian provinces and had approximately 2,730 full-time employees at December 31, 2003. The businesses of the Company have been classified into five segments: Electric, Plastics, Manufacturing, Health Services and Other Business Operations.

	•		Electric (the Utility) includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota under the name Otter Tail Power Company. Electric utility operations have been the Company’s primary business since incorporation.
	•		Plastics consists of businesses producing polyvinyl chloride and polyethylene pipe in the Upper Midwest and Southwest regions of the United States.
	•		Manufacturing consists of businesses in the following manufacturing activities: production of waterfront equipment, wind towers, frame-straightening equipment and accessories for the auto body shop 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, Missouri and Utah.
	•		Health Services consists of businesses involved in the sale of diagnostic medical equipment, patient monitoring equipment and related supplies and accessories. These businesses also provide service maintenance, mobile diagnostic imaging, mobile positron emission tomography and nuclear medicine imaging, portable X-ray imaging and rental of diagnostic medical imaging equipment to various medical institutions located in 42 states.
	•		Other Business Operations consists of businesses in electrical and telephone construction contracting, specialty contracting including design-and-build services for new construction, transportation, telecommunications, energy services and natural gas marketing as well as the portion of corporate general and administrative expenses that are not allocated to other segments. These businesses operate primarily in the Central United States, except for the transportation company which operates in 48 states and 6 Canadian provinces.

     The Company’s electric operations, including wholesale 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 an indirect subsidiary 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 look for acquisitions of additional businesses and expects continued growth in this area. The following acquisitions were completed during 2003:

•

On November 1, 2003 the Company acquired the assets and operations of Foley Company (Foley) for $12.3 million in cash. Foley is a mechanical and prime contracting firm based in Kansas City, Missouri, that provides a range of specialty contracting including design-and-build services for new construction, retrofitting, process piping, equipment settings, and instrumentation and control systems. Major clients include water and wastewater treatment plants, hospital and pharmaceutical facilities, power generation plants, and other industrial and manufacturing projects across a multi-state service area in the Central United States. Foley had gross revenues of $44.8 million in 2002. This acquisition expands the Company’s construction services to a broader geographic region. Foley is included in the Other Business Operations segment.

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•

During 2003, the Company also acquired Topline Medical, Inc. and North Star Medical Systems, Inc. The aggregate price paid for the companies was $1.9 million in cash. These acquisitions will allow the Health Services segment to increase sales opportunities with an expanded line of products.

     The Utility has indicated interest in the South Dakota-based electric and gas operations of NorthWestern Corporation, which filed for bankruptcy in the fall of 2003 and is currently restructuring. The Utility’s interest does not include NorthWestern’s Montana property or operations. Because the process has just begun, it is not possible to determine the likelihood of the acquisition being completed.

     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 2003 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 41 and 42 of the Company’s 2003 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 36% of its consolidated operating revenues from the Electric segment in 2003, 38% in 2002, and 40% in 2001. The breakdown of retail revenues by state is as follows:

     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. The following table provides a breakdown of electric revenues by customer category. All other sources include gross wholesale sales and sales to municipalities and farms.

     Wholesale electric energy sales increased from 45.2% of total kwh sales in 2002 to 50.5% of total kwh sales in 2003. Wholesale electric energy kwh sales grew 24.2% between the years and revenue per kwh increased by 36.1%. Activity in the short-term energy market is subject

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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 2004 will not be as robust as in 2003.

     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, 2003 the Utility served 127,534 customers. This is an increase of 377 customers from December 31, 2002.

Capability and Demand

     At December 31, 2003 and 2002 the Utility had base load net plant capability as follows:

The base load net plant capability for Big Stone Plant and Coyote Station constitutes the Utility’s ownership percentages of 53.9% and 35% respectively.

     In addition to its base load capability, the Utility has combustion turbine and small diesel units owned or under contract, used chiefly for peaking and standby purposes, with a total capability of 142,026 kw, and hydroelectric capability of 4,380 kw. The Utility completed the installation of a peaking combustion turbine in May 2003 with a generation capability of 44,700 kw in summer and 49,500 kw in winter. During 2003, the Utility generated about 79% 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 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. In 2003 the Utility also had a seasonal capacity agreement to purchase 10,000 kw for the months of June and September. The Utility has agreements to purchase the output from approximately 23,000 kw (nameplate rating) of wind generating facilities. 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, 2003 the Utility experienced an all-time system peak demand of 668,703 kw on February 10, 2003. The highest sixty-minute peak demand prior to 2003 was 642,826 kw on December 14, 2000. Taking into account additional capacity available to it in February 2003 under purchase power contracts (including short-term arrangements), as well as its own generating capacity, the Utility’s capability of then meeting system demand, including reserve requirements computed in accordance with accepted industry practice, amounted to 837,590 kw. The Utility’s additional capacity

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available under power purchase contracts (as described above), combined with generating capability and load management control capabilities, is expected to meet 2004 system demand, including industry reserve requirements.

     The Utility and a coalition of other electric providers are funding a study to explore the feasibility of a second electric generating unit, tentatively named Big Stone II, next to the site of the existing Big Stone Plant near Milbank, South Dakota. The project would serve the investing providers’ native customer loads and would be nominally rated between 400 and 600 megawatts, rate-based and coal fired or coal-and-biomass fired. If the investing providers decide to proceed, they are expected to sign ownership and operating agreements in 2004. Permitting, which would require two years, and construction, which would require three years, could lead to the plant being operational in 2010. The Utility’s ownership investment is expected to be less than 25% in the project.

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.

     The following table shows the sources of energy used to generate the Utility’s net output of electricity for 2003 and 2002:

     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 2004. The Company is in negotiations with a new coal supplier for a long-term contract beginning in 2005. 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. The Company is in negotiations with the Kennecott Coal Sales Company for a new coal contract for the Hoot Lake Plant that is expected to be in place before June 30, 2004. Costs are expected to remain stable. 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 early in 2005. 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 on July 31, 2004. The Company is working on a new coal transportation agreement with the Burlington Northern and Santa Fe Railroad for Hoot Lake Plant. The Company is not expecting significant changes to this

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agreement. 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 2003, 2002 and 2001 was $1.189, $1.125, and $1.014, respectively.

     The Utility is permitted by the State of South Dakota to burn some alternative fuels, including tire-derived fuel and biomass, 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:

     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 specialized 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 Utility. 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.

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     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.

     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, 2004. The Company filed its capital structure petition for 2004 on February 13, 2004 and is awaiting action from the MPUC.

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     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 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. Because the Utility’s 2002 rate of return was within the allowable range defined in the plan, no sharing occurred in 2003. The Utility’s 2003 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.

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     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 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. In 2003 SMD met significant political resistance. As a result, FERC published a Wholesale Market Platform (WMP) white paper that provides for regional flexibility and state regulator involvement through Regional State Committees (RSCs). The MISO, with strong FERC encouragement, had established the end of 2003 as a target for MISO markets to be operational within its geographical area of operation. In July 2003, the MISO filed its proposed Transmission and Energy Markets Tariff (TEMT). In October 2003, the MISO withdrew its TEMT. The MISO has stated its plans to refile its TEMT in March of 2004. The MISO is proposing an operational date of December 1, 2004. The MISO is working together with the FERC on this process 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.

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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 2003 legislative session without passing electric industry restructuring legislation or a comprehensive energy bill. There was no legislative action in 2003 regarding electric retail choice in any of the states where the Utility operates and no major electricity legislation is expected in 2004 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, 2003 approximately $6.4 million for environmental control facilities. Included in the 2004-2008 construction budget are approximately $6 million for environmental equipment for existing and new facilities, including $1.1 million for 2004.

     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, and follow-up emission testing is planned for 2004. However, the Department of Energy’s National Energy Technology Laboratory, consultants, equipment vendors and the Utility jointly 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 an on-going effort to refine the demonstration technology.

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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.

     The national NOx emission reduction goals are achieved by imposing mandatory emissions standards on individual sources. 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. All of the Utility’s generating facilities met the NOx standards during 2003.

     The EPA Administrator signed the proposed Interstate Air Quality Rule on December 17, 2003. EPA has concluded that SO2 and NOx are the chief emissions contributing to interstate transport of particulate matter less than 2.5 microns (PM2.5). EPA has also concluded that NOx emissions are the chief emissions contributing to ozone non-attainment. Plans are to finalize the rule by mid-2005. Twenty-eight states and the District of Columbia were found to contribute 0.15 micrograms per cubic meter or more to ambient air quality PM2.5 non-attainment in downwind states. On that basis, EPA is proposing to cap SO2 and NOx emissions in the designated states. Minnesota is included among the 28 states for emissions caps. Twenty-five states were found to contribute to downwind 8-hour ozone non-attainment. None of the states in the Utilities service territory are slated for NOx reduction for ambient air quality 8-hour ozone non-attainment purposes, although EPA is proposing further study of the contributions from the North Dakota and South Dakota. The Utility is evaluating the proposal and is unable to assess its impact until the final rule promulgation.

     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 submitted reports to Congress. The Act required the EPA to 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 published the proposed mercury rule on January 30, 2004. The proposal included two options for regulating mercury emission from coal-fired electric generating units. One option would set technology-based maximum achievable control technology standards under paragraph 111(d) of the Act. The other option embodies a market-based cap and trade approach to emissions reduction. The Utility is currently evaluating the proposal. The EPA expects to issue final rules by December 2004. Because promulgation of rules by the EPA has not been completed, it is not possible to assess to what extent this regulation will impact the Utility.

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     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 responded to that request. In March 2003 the EPA conducted a review of the plant’s outage records as a follow-up to their January 2001 data request. A copy of the designated documents was provided to EPA on March 21, 2003. At this time the Utility cannot determine what, if any, actions will be taken by the EPA. The EPA issued changes to the existing New Source Review rules with respect to routine maintenance and repair and replacement activities in its Equipment Replacement Provision Rule on October 27, 2003. However, the U.S. Court of Appeals for the D.C Circuit issued an order which stayed the effective date of the Equipment Replacement Provision rule pending judicial review. The Utility is awaiting the Court’s decision on the challenges to the rule, which is expected in 2005.

     The Coyote Station is subject to certain emission limitations under the “Prevention of Significant Deterioration” (PSD) program of the Act. The EPA and the North Dakota Department of Health reached an agreement to identify a process for resolving several issues relating to the modeling protocol for the state’s PSD program. A cap on the SO2 emissions could be imposed on all the coal-fired steam-electric generating units that are located in North Dakota, including the Coyote Station, as a result of the modeling effort. If a cap were imposed, it is likely the cap would be set at a level above current actual emission levels. The impact of a cap on SO2 emissions on future operations, if it were imposed, is uncertain.

     The Dakota Resource Council filed a civil action against the EPA asking that the Court order EPA to perform the alleged non-discretionary duty of requiring the State of North Dakota to take steps to remedy alleged unlawful levels of SO2 in Theodore Roosevelt National Park, Lostwood Wilderness Area, Medicine Lakes Wilderness Area, and Fort Pect Indian Reservation. The Utility has joined with other North Dakota utilities in a Motion to Intervene in this proceeding.

     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.

     On February 16, 2004, the EPA Administrator signed the final Phase II rule implementing Section 316(b) of the Clean Water Act establishing standards for cooling water intake structures for certain existing facilities. The rule becomes effective 60 days after its publication in the Federal Register. The Utility is currently evaluating the impact of the rule on its facilities.

     The Utility has all federal and state water permits presently necessary for the operation of the Coyote Station, the Big Stone Plant and the Hoot Lake Plant. The Utility owns five small dams on the Otter Tail River, which are subject to FERC licensing 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, the Big Stone Plant and the Hoot Lake Plant. The Utility completed construction on the first cell of the new ash disposal site at Hoot Lake Plant in 2003, and it is available for use when the existing disposal area is filled later in 2004.

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     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 related 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. The MPCA approved portions of the remediation measures that the Utility proposed and those were implemented in 2003. 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 net income, 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 responsible party under the federal or state Superfund laws.

Capital Expenditures

     The Utility is continually expanding, replacing and improving its electric facilities. During 2003, approximately $28.2 million was invested for additions and replacements to its electric utility properties. During the five years ended December 31, 2003 gross electric property additions, including construction work in progress, were approximately $161.1 million and gross retirements were approximately $53.2 million.

     The Utility estimates that during the five-year period 2004-2008 it will invest approximately $132 million for electric construction. The Utility continuously reviews options for increasing its generating capacity. At this time the Utility has no firm plans for additional base load

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generating plant construction. The majority of electric utility expenditures for the five-year period 2004 through 2008 will be for work related to the Utility’s production plants and distribution system.

Franchises

     At December 31, 2003 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. There are 19 franchises that are set to expire during 2004. The Utility believes that these franchises will be renewed.

Employees

     At December 31, 2003 the Utility had approximately 667 full-time employees. A total of 354 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) and polyethylene (PE) pipe. The Company derived 11% of its consolidated operating revenues from this segment in 2003, 13% in 2002, and 11% in 2001.

	The following is a brief description of these businesses:

	Northern Pipe Products, Inc., located in Fargo, ND, manufactures and sells PVC and PE pipe for municipal water, rural water, wastewater and other uses in the Northern, Midwestern and Western regions of the United States as well as Canada. During 2003, a 45,000-square-foot plant was opened in Hampton, IA for the production of corrugated PE pipe used in drainage and sewer systems.

	Vinyltech Corporation, located in Phoenix, AZ, manufactures and sells PVC pipe for municipal water, wastewater, water reclamation systems and other uses in the Western, Southwest and South Central regions of the United States.

     Together these companies have the capacity to produce approximately 200 million pounds of PVC and PE pipe annually.

Customers

     The PVC and PE pipe products are marketed through a combination of independent sales representatives, company salespersons and customer service representatives. Customers for the PVC and PE 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.

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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 2003, three vendors supplied the resin used, with over 96% of the resin purchased from two main vendors. During 2002, seven vendors supplied the resin used, with over 58% of the resin purchased from two main vendors. In 2001, 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 2003, capital expenditures of approximately $3.9 million were made in the Plastics segment. The 2003 expenditures relate to the opening of the new PE plant in Hampton, IA. Total capital expenditures during the five-year period 2004-2008 are estimated to be approximately $12 million.

Employees

     At December 31, 2003 the Plastics segment had approximately 178 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 body shop industry, custom plastic pallets, material and handling trays and horticultural containers; fabrication of steel products; contract machining; and metal parts stamping and fabrication.

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     The Company derived 24% of its consolidated operating revenues from this segment in 2003, 22% in 2002 and 21% in 2001. 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., located in West Fargo, ND, engineers and manufactures wind towers and other heavy metal fabricated products throughout the United States.

	ShoreMaster, Inc., located in Fergus Falls, MN, along with its wholly owned subsidiary, Galva Foam Marine, Inc. located in Camdenton, MO, produces residential and commercial waterfront equipment, ranging from boatlifts and docks to full marina systems that are marketed 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.

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.

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.

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Steel Supply

     Many of companies in the Manufacturing segment use a variety of steel in the products that they manufacture. Steel prices have increased significantly due to a number of factors including demand from China’s expanding economy, elevated energy prices that increase the cost of making steel, a shortage of coke (a substance made from coal that is used in making steel) and the falling dollar increasing the cost of imported steel. Both pricing and availability are concerns of steel users. Some steel companies are adding surcharges to offset their higher costs. The companies in the Manufacturing segment will attempt to pass the surcharges on to their customers. The increase in steel prices could have a negative affect on profit margins in the Manufacturing segment.

Legislation

     The failure of Congress to pass a broad energy bill in 2003 and extend the Production Tax Credit 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 for the purchase of land and buildings for plant expansion and for investments in management information systems. During 2003, capital expenditures of approximately $9.9 million were made in the Manufacturing segment. Total capital expenditures for the Manufacturing segment during the five-year period 2004-2008 are estimated to be approximately $43 million.

Employees

     At December 31, 2003 the Manufacturing segment had approximately 1,067 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, patient monitoring equipment and related supplies and accessories. These businesses also provide service maintenance, mobile diagnostic imaging, mobile positron emission tomography and nuclear medicine imaging, portable X-ray imaging and rental of diagnostic medical imaging equipment.

     During 2003, two small acquisitions were completed in this segment, Topline Medical, Inc. and North Star Medical Systems, Inc. These companies sell cardiac patient monitoring equipment to healthcare facilities in the Upper Midwest.

     The Company derived 13% of its consolidated operating revenues from this segment in 2003 and 14% in 2002 and 2001. The companies comprising the DMS Health Group include:

DMS Health Technologies, Inc. (DMS), located in Fargo, ND, sells, services and refurbishes diagnostic medical imaging equipment, patient monitoring 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. In December 2003 the Company’s dealership agreement with Philips was renewed. 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.

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DMS Imaging, Inc., a subsidiary of DMS Health Technologies, Inc. located in Minneapolis, 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 42 states. Regional offices are located in Houston, TX; Minneapolis, MN; and Sioux Falls, SD. DMS Imaging provides services in four different business units:

	•		DMS Imaging - provides shared diagnostic medical imaging services (primarily mobile) for MRI, CT, nuclear medicine, PET, ultrasound, mammography and bone density analysis.
	•		DMS Interim Solutions - offers interim and rental options for diagnostic imaging services.
	•		DMS MedSource Partners - develops partnerships with healthcare providers to offer dedicated in-house diagnostic imaging services, such as MRI.
	•		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, payment of services and addition of facilities and 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 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 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 consolidated financial results.

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     The Health Insurance Portability and Accountability Act of 1996 (HIPAA) created federal crimes related to healthcare fraud and to making false statements related to healthcare matters. HIPAA prohibits knowingly and willfully executing a scheme to defraud any healthcare benefit program including a program involving private payors. Further, HIPAA 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 HIPAA is a felony and may result in fines, imprisonment or exclusion from government-sponsored programs such as Medicare and Medicaid. Finally, HIPAA creates federal privacy standards for individually identifiable health information and computer security standards for all health information. These standards became applicable in 2003 and the Health Services companies believe that they are in compliance with the requirements of HIPAA. 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 payors, 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 customers’ health insurance 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, patient monitoring equipment 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 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 technologists. The companies in the Health Services segment may also experience greater competition in states that currently have certificate of need 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

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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 imaging business. During 2003, capital expenditures of approximately $5.4 million were made in the Health Services segment. Total capital expenditures during the five-year period 2004-2008 are estimated to be approximately $5 million. Operating leases are also used to finance the acquisition of medical equipment used by Health Services companies. Current operating lease commitments during the five-year period 2004-2008 are estimated to be $46 million.

Employees

     At December 31, 2003 the Health Services segment had approximately 410 full-time employees.

OTHER BUSINESS OPERATIONS

General

     Other Business Operations consists of businesses engaged in electrical and telephone construction contracting, specialty contracting including design-and-build services for new construction, transportation, telecommunications, energy services and natural gas marketing as well as the portion of corporate general and administrative expenses that are not allocated to the other segments.

     On November 1, 2003 the Company acquired the assets and operations of Foley Company.

     The Company derived 16% of its consolidated operating revenues from these businesses in 2003 and 13% in 2002 and 14% in 2001. Following is a brief description of each of these businesses.

Foley Company, headquartered in Kansas City, MO, provides mechanical and prime contracting services including design-and-build services for new construction, retrofitting, process piping, equipment settings and instrumentation and control systems. Major clients include water and wastewater treatment plants, power generation plants, hospital and pharmaceutical facilities, power generation plants and other industrial and manufacturing projects across a multi-state service area in the Central United States.

	Midwest Construction Services, Inc., located in Moorhead, MN, is a holding company for five subsidiaries that provide electrical design

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	and construction services for the industrial, commercial and municipal business markets, including government, institutional, communications, utility and renewable energy projects in the Upper Midwest.

	Midwest Information Systems, Inc., headquartered in Parkers Prairie, MN, provides telephone, cable and internet services with over 10,000 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. During 2003 operations within this company were scaled back to providing technical and engineering services, energy efficient lighting, and retail marketing of natural gas and energy management services to 150 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. Wylie has trucking terminals in Fargo, ND, Des Moines, IA, Fort Worth, TX, and Chicago, IL.

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 with the MPUC for approval. 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 and the Central regions of the United States 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, construction equipment and infrastructure to support the telephone, cable and internet services. During 2003, capital expenditures of approximately $3.2 million were made in Other Business Operations. Capital expenditures during the five-year period 2004-2008 are estimated to be approximately $16 million for Other Business Operations. The majority of the capital expenditures in the five-year period 2004-2008 will be used to replace existing equipment mainly in the telecommunication and construction companies.

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Employees

     At December 31, 2003 there were approximately 408 full-time employees in Other Business Operations. 105 employees of Moorhead Electric, Inc. are represented by local unions of the International Brotherhood of Electrical Workers and were covered by a two-year labor contract that expired May 31, 2003. Provisions exist under the labor contract that extended that contract until May 31, 2004. 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 diversification efforts, growth of electric revenues, the timing and scope of deregulation and open competition, Federal Energy Regulatory Commission mandated operational changes to the electricity transmission grid, impact of the investment performance of the Utility’s pension plan, changes in the economy, weather conditions, market valuation of forward energy contracts, availability of resin suppliers, resin prices, steel prices, governmental and regulatory action, fuel and purchased power costs, environmental issues, and other factors discussed under “Critical Accounting Policies Involving Significant Estimates” and “Factors Affecting Future Earnings” on pages 24 through 27 of the Company’s 2003 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.