SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

þ		Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2005

o		Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from                     to

Commission File Number 0-368

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

MINNESOTA		41-0462685
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
215 SOUTH CASCADE STREET BOX 496, FERGUS FALLS, MINNESOTA		56538-0496
(Address of principal executive offices)		(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act: 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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. (Yes þ No o)

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. (Yes o Noþ )

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 þ No o)

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of 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. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer þ		Accelerated Filer o		Non-Accelerated Filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). (Yes o No þ)

The aggregate market value of the voting stock held by nonaffiliates, computed by reference to the last sales price, on June 30, 2005 was $774,287,870.

Indicate the number of shares outstanding of each of the registrant’s classes of Common Stock, as of the latest practicable date: 29,438,047 Common Shares ($5 par value) as of February 28, 2006.

Documents Incorporated by Reference:

 

 

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, P.O. Box 496, Fergus Falls, Minnesota 56538-0496 and 4334 18^th 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, Forms 3, 4 and 5 filed on behalf of directors and executive officers 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 then 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 2005, approximately 30% of the Company’s consolidated operating revenues from continuing operations and approximately 71% of the Company’s consolidated net income from continuing operations came from electric operations.

          The Company’s vision is to create value and growth through ownership and acquisition of well-run companies in diverse businesses. The strategy is straightforward: reliable utility performance combined with growth opportunities at all our businesses provides long-term value. This includes growing the core electric utility business which provides a strong base of revenues, earnings and cash flows. In addition, the Company looks to its nonelectric operating companies to provide growth both organically and through acquisitions. Organic, internal growth comes from new products and services, market expansion and increased efficiencies. The Company adheres to strict guidelines when reviewing acquisition candidates since its aim is to add companies that will produce an immediate positive impact on earnings and provide long-term growth potential. Owning well-run, profitable companies across different industries can bring more growth opportunities and more balance to results. In doing this, the Company also avoids concentrating business risk within a single industry. All of the operating companies operate under a decentralized business model with disciplined corporate oversight.

          The Company assesses the performance of its operating companies over time, using criteria that include:

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

The Company is a long-term owner of its operating companies and does not acquire companies in pursuit of short-term gains. However, the Company will divest operating companies if they do not meet these criteria over the long term.

          Otter Tail Corporation and its subsidiaries conducted business in all 50 states and in international markets. The Company had approximately 3,259 full-time employees at December 31, 2005. The businesses of the Company have been classified into six segments: Electric, Plastics, Manufacturing, Health Services, Food Ingredient Processing and Other Business Operations.

	•		Electric (the Utility) consists of 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 consist 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; material and handling trays and horticultural containers; contract machining; and metal parts stamping and fabrication. These businesses have manufacturing facilities in Minnesota, North Dakota, South Carolina, Missouri, California, Florida and Ontario, Canada and sell products primarily in the United States.
	•		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 equipment maintenance, diagnostic imaging services and rental of diagnostic medical imaging equipment to various medical institutions located throughout the United States.
	•		Food Ingredient Processing consists of Idaho Pacific Holdings, Inc. (IPH), which owns and operates potato dehydration plants in Ririe, Idaho; Center, Colorado and Souris, Prince Edward Island, Canada. IPH produces dehydrated potato products that are sold in the United States, Canada, Europe, the Middle East, the Pacific Rim and Central America. Approximately 25% of IPH’s sales are to customers outside of the United States.
	•		Other Business Operations consists of businesses involved in residential, commercial and industrial electric contracting industries; fiber optic and electric distribution systems; waste-water, water and HVAC systems construction; transportation; 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 a subsidiary of Otter Tail Corporation. Substantially all of the other businesses are owned by the Company’s wholly-owned subsidiary, Varistar Corporation (Varistar).

          The Company considers the following guidelines 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 continues to look for acquisitions of additional businesses and expects continued growth in this area. The following acquisitions in the Manufacturing segment were completed during 2005:

	•		On January 3, 2005 the Company’s wholly-owned subsidiary, BTD Manufacturing, Inc. acquired the assets of Performance Tool & Die, Inc. of Lakeville, Minnesota for $4.1 million in cash. Performance Tool & Die specializes in manufacturing mid to large progressive dies for customers throughout the Midwest, East and West Coasts, and the Southern United States. Performance Tool & Die’s revenues for the year ended December 31, 2004 were $4.1 million. The Company expects this acquisition to provide expanded growth opportunities for both BTD Manufacturing and Performance Tool & Die.
	•		On January 3, 2005 the Company’s wholly-owned subsidiary, ShoreMaster, Inc. acquired the common stock of Shoreline Industries, Inc. of Pine River, Minnesota for $2.4 million in cash. Shoreline is a manufacturer of boatlift motors and other accessories for lifts and docks with sales throughout the United States, but primarily in Minnesota and Wisconsin. Shoreline’s revenues for the year ended December 31, 2004 were $2.1 million. The acquisition of Shoreline secures a source of components and expands potential markets for ShoreMaster products.
	•		On May 31, 2005 ShoreMaster acquired the assets of Southeast Floating Docks, Inc. of St. Augustine, Florida for $4.0 million in cash. Southeast Floating Docks is a leading manufacturer of concrete floating dock systems for marinas. They have designed custom floating systems and conducted installations mainly in the Southeast United States and the Caribbean. Southeast Floating Docks had revenues of $4.5 million in 2004. This acquisition enables ShoreMaster to offer a wider range of products to its customers and expands its geographic reach in the Southeast region of the United States.

For financial information regarding these businesses, see note 2 of “Notes to Consolidated Financial Statements” on page 45 of the Company’s 2005 Annual Report to Shareholders, filed as an Exhibit hereto.

          As part of an ongoing evaluation of the prospects and growth opportunities of the Company’s business operations, the Company completed the sale of three businesses during 2005, Midwest Information Systems, Inc. (MIS), St. George Steel Fabrication, Inc. (SGS) and Chassis Liner Corporation (CLC).

	•		In June 2005, the Company completed the sale of MIS, a telecommunications company located in Parkers Prairie, Minnesota, for an after-tax gain of $11.9 million.
	•		Also in June 2005, the Company completed the sale of SGS, a structural steel fabricator located in St. George, Utah, for an after-tax loss of $1.7 million.
	•		In November 2005, the Company completed the sale of CLC, a manufacturer of auto and truck frame-straightening equipment and accessories located in Alexandria, Minnesota, for an after-tax loss of $0.2 million.

          As required in accordance with Statement of Financial Accounting Standard No. 144, Accounting for the Impairment of Disposal of Long-Lived Assets, MIS, SGS and CLC were accounted for as discontinued operations in the Company’s consolidated financial statements which are incorporated by reference and filed as an Exhibit hereto. MIS was included in discontinued operations starting in 2004. Prior to 2004, MIS was included in the Other Business Operations segment. Prior to 2005, SGS and CLC were included in the Manufacturing segment. For financial information regarding these businesses see note 15 of “Notes to Consolidated Financial Statements” on pages 56 and 57 of the Company’s 2005 Annual Report to Shareholders, filed as an Exhibit hereto.

          Starting in April 2005, the Midwest Independent Transmission System Operator (MISO) initiated a regional wholesale energy market using locational marginal pricing and Financial Transmission Rights – Day 2 market. The Day 2 market is intended to provide a more efficient generation dispatch over the MISO region. For a further description of the Day 2 market and its impact on the Utility, see “Narrative Description of Business—Electric—General.” It is expected that the Day 2 market will provide efficiencies and long-term benefits through dispatch of power from the most cost-effective source of generation or transmission; however there are costs to the Utility relating to the Day 2 market. The Utility has requested recovery of these costs from the respective regulatory jurisdictions. For further discussion, see “Narrative Description of Business—Electric—General Regulation.”

          On June 30, 2005 the Utility and a coalition of six other electric providers entered into agreements for the development of Big Stone II, a proposed 600-megawatt coal-fired electric generating plant adjacent to the existing Big Stone Plant near Milbank, South Dakota. For a further description of this project, see “Narrative Description of the Business—Electric—Big Stone II.”

          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 33 of the Company’s 2005 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 six segments: Electric, Plastics, Manufacturing, Health Services, Food Ingredient Processing and Other Business Operations. Financial information about the Company’s segments and geographic areas is incorporated by reference to note 2 of “Notes to Consolidated Financial Statements” on pages 45 through 47 of the Company’s 2005 Annual Report to Shareholders, filed as an Exhibit hereto.

          (c) Narrative Description of Business

ELECTRIC

General

          The Utility provides electricity to more than 128,000 customers in a 50,000 square mile area of Minnesota, North Dakota and South Dakota. The Company derived 30%, 31% and 37% of its consolidated operating revenues from the Electric segment for each of the three years ended December 31, 2005, 2004 and 2003, respectively. The Company derived 71%, 78% and 89% of its consolidated income from continuing operations from the Electric segment for each of the three years ended December 31, 2005, 2004 and 2003, respectively. The breakdown of retail revenues by state is as follows:

State		2005				2004
Minnesota			50.3	%			50.3	%
North Dakota			40.9				41.2
South Dakota			8.8				8.5
Total			100.0	%			100.0	%

          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 from Utility generation, net revenue from energy trading activity and sales to municipalities.

Customer category		2005				2004
Commercial			33.5	%			35.3	%
Residential			28.1				30.3
Industrial			20.9				21.5
All other sources			17.5				12.9
Total			100.0	%			100.0	%

          Wholesale electric energy kwh sales were 41.6% of total kwh sales for 2005 and 50.5% for 2004. Wholesale electric energy kwh sales decreased 27.7% between the years and revenue per kwh increased by 32.4%. 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.

          With the inception of the Midwest Independent Transmission System Operator (MISO) Day 2 markets in April 2005, MISO introduced two new types of contracts, virtual transactions and Financial Transmission Rights (FTR). Virtual transactions are of two types: Virtual Demand Bid, which is a bid to purchase energy in MISO’s Day-Ahead Market that is not backed by physical load and Virtual Supply Offer which is an offer submitted by a market participant in the Day-Ahead Market to sell energy not supported by a physical injection or reduction in withdrawals in commitment by a resource. An FTR is a financial contract that entitles its holder to a stream of payments, or charges, based on transmission congestion charges calculated in MISO’s Day-Ahead Market. A market participant can acquire an FTR from several sources: the annual or monthly FTR allocation based on existing entitlements, the annual or monthly FTR auction, the FTR secondary market, or a grant of an FTR in conjunction with a transmission service request. An FTR is structured to hedge a market participant’s exposure to uncertain cash flows resulting from congestion of the transmission system. In 2005, net revenues from virtual and FTR transactions represented 4.9% of total electric energy revenues. As the MISO markets evolve and become more efficient, the Utility expects that profits from virtual and FTR transactions may be reduced and downward pressures will continue on wholesale trading margins.

          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, 2005 the Utility served 128,466 customers. This is an increase of 248 customers over December 31, 2004.

Capability and Demand

          As of December 31, 2005 and 2004 the Utility had base load net plant capability as follows:

Base load net plant capability		2005				2004
Big Stone Plant		256,025		kw		252,430		kw
Hoot Lake Plant			153,700				152,450
Coyote Station			149,450				149,450
Co-generation plant – Bemidji, MN (contract)			5,862				5,661
Co-generation plant – Perham, MN (contract)			1,242				1,228
Total		566,279		kw		561,219		kw

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. The Utility owns 100% of the Hoot Lake Plant.

          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 142,973 kw, and hydroelectric capability of 4,244 kw. During 2005, the Utility generated about 63% 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 to purchase 50,000 kw of year-round capacity through April 30, 2010. The Utility has agreements to purchase the output from approximately 23,000 kw (nameplate rating) of wind generating facilities. The December 2005 capacity rating of the wind generating facilities was 6,890 kw. Surplus energy is received from another 2,300 kw (nameplate rating) of wind generation that customers use to supply some of their own load. 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, 2005 the Utility experienced a system peak demand of 665,064 kw on February 7, 2005. The highest all-time system peak demand was 686,044 kw on January 5, 2004. Taking into account additional capacity available to it on February 7, 2005 under purchase power contracts (including short-term arrangements), as well as its own generating capacity, the Utility’s capability of then meeting system demand, excluding reserve requirements computed in accordance with accepted industry practice, amounted to 836,250 kw (759,720 kw if reserve requirements are included). 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 2006 system demand, including industry reserve requirements.

Big Stone II

          On June 30, 2005 the Utility and a coalition of six other electric providers entered into several agreements for the development of a second electric generating unit, named Big Stone II, at the site of the existing Big Stone Plant near Milbank, South Dakota. The three primary agreements are the Participation Agreement, the Operation and Maintenance Agreement and the Joint Facilities Agreement. Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc., Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency are parties to all three agreements. NorthWestern Corporation is an additional party to the Joint Facilities Agreement.

          The Participation Agreement is an agreement to jointly develop, finance, construct, own (as tenants in common) and manage the Big Stone II Plant. The Participation Agreement includes provisions which obligate the parties to the agreement to obtain financing and pay their share of development, construction, operating and maintenance costs for the Big Stone II Plant. It also provides for the sharing of the plant output. Estimated construction costs for the plant are expected to be approximately $1.2 billion. The Participation Agreement provides that the Utility shall pay for and own 19.33% of the Big Stone II Plant and be entitled to a corresponding interest in the plant’s electrical output. The project participants included in the Participation Agreement a section covering withdrawal rights due to higher than anticipated project costs. At a time agreed to by the participants, comparisons of the then-current project costs will be made against the costs projected in 2005. Higher than anticipated project costs gives each participant certain withdrawal rights. The Participation Agreement establishes a Coordinating Committee and an Engineering and Operating Committee to manage the development, design, construction, operation and maintenance of the Big Stone II Plant.

          The Operation and Maintenance Agreement designates the Utility as the operator of the Big Stone II Plant. As operator, the Utility is required to provide staff and resources for the development, design, financing, construction and operation of the Big Stone II Plant. The other project participants are each

6

required to reimburse the Utility for their respective share of the costs relating to those activities. The Coordinating Committee and the Engineering and Operating Committee, which are made up of representatives of all project participants, are authorized to supervise the Utility in its role as operator.

          The Joint Facilities Agreement provides for the transfer of certain real property and easements from the Big Stone I Plant owners to the Big Stone II Plant participants and for the shared use of certain equipment and facilities between the two plants. The Joint Facilities Agreement also allocates between the two Plants the costs of operation and maintenance of the shared equipment and facilities.

          The proposed project is intended to serve the owners’ native customer loads, will be nominally rated 600 megawatts, will be rate-based and will be coal fired or coal-and-biomass fired. The proposed project will meet air emission requirements as prescribed by the Environmental Protection Agency and the South Dakota Department of Environment and Natural Resources. Black and Veatch, a Kansas City based engineering firm has been selected to do the plant design work. They have begun the conceptual design work and are expected to have this phase completed by early this summer. The five major procurement packages are in the process of being completed and all five are expected to be out for proposals this spring.

          The owners are in the process of securing the permits required for construction and operation of the project, including siting permits, air emission permits and the certificate of need for transmission. In addition a draft of an environmental impact statement (EIS) is expected to be published in April, 2006 with an EIS Record of Decision in November 2006. All major permits have been filed and are on schedule to be finalized by February 2007. Financial close, which requires the participants to provide binding financial commitments to support their share of costs, is to occur 90 days after the EIS Record of Decision. The financial close is not expected until early 2007. No one can predict the exact outcome of any of these proceedings and the Utility expects a number of interveners in the permitting process. If the necessary approvals are received and plans progress, groundbreaking is expected to take place in 2007 with the plant in service by 2011.

Fuel Supply

          Coal is the principal fuel burned at the Big Stone, Coyote and Hoot Lake generating plants. Coyote Station, 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 2005 and 2004:

		2005								2004
		Net Kilowatt				% of Total				Net Kilowatt				% of Total
		Hours				Kilowatt				Hours				Kilowatt
		Generated				Hours				Generated				Hours
Sources		(Thousands)				Generated				(Thousands)				Generated
Subbituminous Coal			2,410,719				68.6	%			2,605,014				69.0	%
Lignite Coal			1,043,020				29.7				1,114,485				29.5
Hydro			23,446				.7				20,689				.6
Natural Gas and Oil			36,520				1.0				33,927				.9
Total			3,513,705				100.0	%			3,774,115				100.0	%

          The Utility has the following primary coal supply agreements:

Plant		Coal Supplier		Type of Coal		Expiration Date
Big Stone Plant		Arch Coal Sales Company, Inc.		Wyoming subbituminous		December 31, 2007
Big Stone Plant		Kennecott Coal Sales Company		Wyoming subbituminous		December 31, 2007
Hoot Lake Plant		Kennecott Coal Sales Company		Wyoming subbituminous		December 31, 2007
Coyote Station		Dakota Westmoreland Corporation		North Dakota lignite		2016

The contract with Dakota Westmoreland Corporation has 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 and a 20-day inventory at the Coyote Station and 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. The Company filed a complaint in regard to this rate with the Surface Transportation Board requesting the Board set a competitive rate. On January 27, 2006 the Surface Transportation Board issued a final decision dismissing the case. The Company is reviewing the Board’s decision and analyzing its options. No decision has been made at this time whether or not to pursue an appeal of the decision. If the Company decides to take no further action, then railroad transportation services to the Big Stone Plant will continue to be provided under the common carrier rate. Railroad transportation services to the Hoot Lake Plant are being provided under a common carrier rate by the Burlington Northern and Santa Fe Railroad. On July 1, 2004, the Burlington Northern and Santa Fe Railroad implemented a fuel surcharge that applies to both Hoot Lake and Big Stone Plants. The fuel surcharge is based on the U.S. average price of retail on-highway diesel fuels. During 2005 the fuel surcharge, which is in addition to the freight rate, ranged from 9.0% to 23.5% as a percent of the tariff rate. On January 1, 2006, the Burlington Northern and Santa Fe Railroad implemented a new mileage-based methodology to assess fuel surcharges. The basis for the fuel surcharge is still the U.S. average price of retail on-highway diesel fuel. 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 2005, 2004 and 2003 was $1.339, $1.229 and $1.189, 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.

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:

						2005								2004
						% of				% of				% of				% of
						Electric				kwh				Electric				kwh
Rates		Regulation				Revenues				Sales				Revenues				Sales
MN retail sales		MN Public Utilities Commission					31.2	%			30.2	%			29.3	%			25.7	%
ND retail sales		ND Public Service Commission					25.3				22.9				24.1				19.6
SD retail sales		SD Public Utilities Commission					5.5				5.2				4.9				4.2
Transmission & sales for resale		Federal Energy Regulatory Commission					38.0				41.7				41.7				50.5
							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 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 the Federal Energy Regulatory Commission (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 period after becoming applicable.

          The following summarizes the material regulations of each jurisdiction applicable to the Utility’s electric operations, as well as any 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 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 one year 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 submitted its most recent integrated resource plan on July 1, 2005. MPUC action on that plan is pending.

          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 the Commission issues a new capital structure order for 2006. The Company filed its capital structure petition for 2006 on February 13, 2006 and expects to receive approval from the MPUC prior to May 31, 2006.

          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 associated with each method of electricity 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 MPUC 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 MPUC is empowered, after an environmental impact study is conducted by the DOC and the Office of Administrative Law conducts contested case 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 Utility and the coalition of six other electric providers filed an application for a Certificate of Need for the Minnesota portion of the Big Stone II transmission line project

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on October 3, 2005 and filed an application for a Route Permit for the Minnesota portion of the Big Stone II transmission line project with the MPUC on December 9, 2005. Evidentiary hearings are expected in October 2006 with possible action by the MPUC in February 2007.

          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. This legislation also changed the environmental review authority from the Environmental Quality Board to the DOC.

          In September 2004, a letter was provided to the MPUC summarizing issues and conclusions of an internal investigation completed by the Company as it related to claims of allegedly improper regulatory filings brought to the attention of the Company by certain individuals. On November 30, 2004 the Utility filed a report with the MPUC responding to these claims. In 2005, the Energy Division of the DOC, the Residential Utilities Division of the Office of Attorney General and the claimants filed comments in response to the report, to which the Company filed reply comments. A hearing before the MPUC was held on February 28, 2006. As a result of the hearing the Utility agreed that within the next 60 to 90 days it would file a revised Regulatory Compliance Plan, an updated Corporate Cost Allocation Manual and documentation of the definitions of its chart of accounts. The Utility also agreed to file a general rate case in Minnesota on or before September 30, 2007.

          In December 2005 the MPUC issued a decision denying the Utility’s request to allow recovery of certain MISO-related costs through the fuel clause adjustment (FCA) in Minnesota retail rates and requiring a refund of amounts previously collected pursuant to an interim order issued in April 2005. A $1.9 million reduction in revenue and a refund payable was recorded in December 2005 by the Utility to reflect the refund obligation. On February 9, 2006 the MPUC decided to reconsider its December 2005 order. The Commission’s final order was issued on February 24, 2006. In the order the MPUC requested that within 60 days the Minnesota utilities that were party to this order determine which MISO-related costs are appropriately included in the FCA and which costs would be more appropriately recovered through base rates. In addition, the order eliminated the refund provision from the December 2005 order, and allowed that any MISO-related costs not recovered through the FCA may be deferred for a period of 36 months, with possible recovery through base rates in the Utility’s next general rate case which is expected to be filed on or before September 30, 2007. As a result of this order, the Utility recognized $1.9 million in revenue and reversed the refund payable in February 2006 and expects to recover all MISO-related costs through the FCA, or to seek recovery, in a rate case, of any MISO-related costs not recoverable through the FCA.

          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 100,000 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.

          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.

          On December 29, 2000 the NDPSC approved a performance-based ratemaking (PBR) plan that links allowed earnings in North Dakota to seven defined performance standards in the areas of price, electric service reliability, customer satisfaction and employee safety. The PBR plan provided 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 PBR 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, 2003 and 2004 rates of return were within the allowable range defined in the PBR plan, no sharing occurred. The Utility’s 2005 rate of return is expected to be within the allowable range defined in the PBR plan. The PBR plan expired on December 31, 2005. While the Utility has applied to the NDPSC for a 3-year extension with certain modifications, the NDPSC has taken no action on the extension.

          In September 2004, a letter was provided to the NDPSC summarizing issues and conclusions of an internal investigation completed by the Company as it related to claims of allegedly improper regulatory filings brought to the attention of the Company by certain individuals. The NDPSC has not opened a formal docket, but its staff has been reviewing the issues. The Company has responded to various data requests and met with staff. The Company will continue to work with staff and the NDPSC to resolve issues raised by the internal investigation.

          In February 2005, the Utility filed with the NDPSC a petition to seek recovery of certain MISO-related costs through the FCA. The NDPSC granted interim recovery through the FCA in April 2005, but similar to the decision of the MPUC, conditioned the relief as being subject to refund until the merits of the case are determined. The NDPSC has taken no further action regarding this filing.

          South Dakota: Under the South Dakota Public Utilities Act, the Utility is subject 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. The Utility and the coalition of six other electric providers filed an Energy Conversion Facility Siting Permit Application with the SDPUC for the Big Stone II plant on July 21, 2005 and a decision on the application is expected in July 2006. A permit application for the South Dakota portion of the transmission line was filed with the SDPUC on January 16, 2006 and a decision on that application is expected in January 2007.

          In September 2004, a letter was provided to the SDPUC summarizing issues and conclusions of an internal investigation completed by the Company as it related to claims of allegedly improper regulatory filings brought to the attention of the Company by certain individuals. There has been no additional correspondence between the Company and the SDPUC related to these issues.

          In March 2005, the Utility filed with the SDPUC a petition to seek recovery of certain MISO-related costs through the FCA. The SDPUC approved the request in April 2005.

          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 Comprehensive Energy Policy Act of 2005 (the 2005 Energy Act) signed into law in August 2005, will substantially affect the regulation of energy companies, including the Utility. The 2005 Energy Act amends federal energy laws and provides the FERC with new oversight responsibilities. Among the important changes to be implemented as a result of this legislation are the following:

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The Public Utility Holding Company Act of 1935 (PUHCA) was repealed effective February 8, 2006. PUHCA significantly restricted mergers and acquisitions in the electric utility sector.

	•		The FERC will appoint and oversee an electric reliability organization to establish and enforce mandatory reliability rules regarding the interstate electric transmission system. It is expected that the electric reliability organization will be approved and begin operation by mid-year 2006.
	•		The FERC will establish incentives for transmission companies, such as performance based rates, recovery of costs to comply with reliability rules and accelerated depreciation for investments in transmission infrastructure.
	•		Federal support will be available for certain clean coal power initiatives, nuclear power projects and renewable energy technologies.

          The implementation of the 2005 Energy Act requires proceedings at the state level and the development of regulations by the FERC and the Department of Energy, as well as other federal agencies. The Company cannot predict when these proceedings and regulations will commence or be finalized. The Company is still studying the legislation and its effect and cannot predict with certainty the impact on its electric operations.

          In a letter from the FERC Office of Market Oversight and Investigations (OMOI) dated September 27, 2005 the Utility was informed that the Division of Operation Audits of the OMOI would be commencing an audit of the Utility. The purpose of the audit is to determine whether and how the Company’s transmission practices are in compliance with the FERC’s applicable rules and regulations and tariff requirements and whether and how the implementation of the Company’s waivers from the requirements of Order No. 889 and Order No. 2004 restricts access to transmission information that would benefit the Company’s off-system sales. The audit will cover the period from January 1, 2003 through August 31, 2005. This is a routine audit to which all FERC jurisdictional utilities are subject. The audit is expected to take approximately six months to complete. The Utility believes it is in compliance with applicable FERC rules, regulations and tariff requirements related to the audit. Given the preliminary status of this audit, the Utility is not able to determine whether the audit will result in any material changes to the Utility’s operations or have any material effect on the Utility’s net income, financial position or cash flow.

          MAPP: The Utility participates in the Mid-Continent Area Power Pool (MAPP) generation reserve sharing pool, which operates in parts of eight states in the Upper Midwest and in three provinces in Canada.

          MEMA: The Utility is a member of the Mid-Continent Energy Marketers Association (MEMA) which is an independent, non-profit trade association representing entities involved in the marketing of energy or in providing services to the energy industry. MEMA operates in the MAPP, MISO, Southwest Power Pool, PJM Interconnection, LLC and Southeast regions and was formed in 2003 as a successor organization of the Power and Energy Market of MAPP. Power pool sales are conducted continuously through MEMA in accordance with schedules filed by MEMA with the FERC.

          MRO: The Utility is a member of the Midwest Reliability Organization (MRO). The MRO, a non-profit organization that replaced the MAPP Regional Reliability Council, is one of 10 Regional Reliability Councils that comprise the North American Electric Reliability Council (NERC). The MRO is a voluntary organization committed to ensuring the reliability of the bulk power system in the Midwest part of North America. The MRO, through its balanced stakeholder board with independent oversight, operates independently from any member, market participant or operator, so that the standards developed and enforced by the MRO are fair and administered without undue influence from market participants. The MRO is approximately 40% larger in terms of net end use load than MAPP. The MRO region includes more than 40 members supplying approximately 280 million megawatt-hours to more than 20 million people. Its membership is comprised of municipal utilities, cooperatives, investor-owned utilities, a federal power marketing agency, Canadian Crown Corporations and independent power producers.

          MISO: The Utility is a member of the Midwest Independent Transmission System Operator, Inc. (MISO). As expressed in FERC Order No. 2000, FERC’s view is that independent regional transmission organizations will benefit the public interest by enhancing the reliability of the electric grid and providing unbiased regional grid management, nondiscriminatory operation of the bulk power transmission system and open access to the transmission facilities under MISO’s functional supervision. 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 seeks to optimize the efficiency of the interconnected system, provide regional solutions to regional planning needs and minimize risk to reliability through its security coordination, long-term regional planning, market monitoring, scheduling and tariff administration functions.

          The MISO Energy Markets commenced operation on April 1, 2005. Through its Energy Markets, MISO seeks to develop options for energy supply, increase utilization of transmission assets, optimize the use of energy resources across a wider region and provide greater visibility of data. MISO aims to facilitate a more cost-effective and efficient use of the wholesale bulk electric system. The MISO Energy Market is intended to improve efficiency and price transparency, which may reduce the Utility’s opportunity for traditional marketing profits. The effects of the MISO Energy Market on the Utility’s retail customers, including costs to those customers, and the Utility’s wholesale margins are expected to vary through the transition.

          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, and the 2005 Energy Act described above.

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. There has been no legislative action regarding electric retail choice in any of the states where the Utility operates and no major electricity legislation is expected in 2006 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.

          The Utility is unable to predict the impact on its operations resulting from future regulatory activities, from future legislation or from future taxes that may be imposed on the source or use of energy.

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. In the five years ended December 31, 2005 the Utility invested approximately $9.2 million in

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environmental control facilities. The 2006-2010 construction budget includes approximately $22.0 million for environmental equipment for existing and new facilities, including $13.0 million for the Utility’s portion of a scrubber which will be shared between the current Big Stone Plant and the proposed Big Stone II Plant. Environmental expenditures for 2006 are expected to be $3.4 million.

          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. Hoot Lake Plant unit 1 turbine generator, which is the smallest of the three coal-fired units at Hoot Lake Plant, was retired as of December 31, 2005. The Utility currently plans to retain the unit 1 boiler for use as a source of emergency heat. A fabric filter to collect particulates from stack gases was installed on Hoot Lake Plant unit 1. As a result, the Utility believes the units at the Hoot Lake Plant currently meet all presently applicable federal and state air quality and emission standards.

          A major portion of the Big Stone Plant’s electrostatic precipitator was replaced in 2002 with an Advanced Hybrid™ technology that was installed as part of a demonstration project co-funded by 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. The Department of Energy’s National Energy Technology Laboratory, consultants, equipment vendors and the Utility have assessed the operational performance of the unit and its balance-of-plant impacts as part of the ongoing effort to refine the demonstration technology. Even though Big Stone Plant co-owners replaced the remaining four precipitator fields with Advanced Hybrid™ technology in 2005, the technology continues to impose limits on plant output. The Big Stone Plant co-owners are evaluating particulate emissions control technology options. 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 2005.

          The EPA Administrator signed the final Interstate Air Quality Rule, also known as the Clean Air Interstate Rule, on March 10, 2005. 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. Twenty-three states and the District of Columbia were found to contribute 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 twenty-three states for emissions caps. Twenty-five states were found to contribute to downwind 8-hour ozone non-attainment. None of the states in the Utility’s service territory are slated for NOx reduction for ambient air quality 8-hour ozone non-attainment purposes. Based on the Utility’s assessment of the likely requirements, either additional NOx emissions control equipment will need to be installed on Hoot Lake Plant units 2 and 3 or NOx allowances will need to be purchased for those emissions in excess of the allowance allocation beginning in 2009. The 2006 capital budget includes $2 million for NOx emissions control equipment that would be installed on Hoot Lake Plant unit 3. Additional NOx emission control equipment is slated for installation in 2007 on Hoot Lake Plant unit 2 at a similar cost. The Utility expects that the installation of NOx emission control equipment will allow Hoot Lake Plant units 2 and 3 to be in compliance.

          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 EPA published final rules in May 2005. On October 28, 2005 EPA announced a reconsideration of portions of the final rules. Because the rules are currently under review by EPA, it is not possible to assess 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 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 2006.

          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. Modeling was completed and the results were submitted to the EPA for their review. On April 19, 2005 the North Dakota Department of Health held a Periodic Review Hearing relating to the PSD Air Quality Modeling Report that was submitted to the EPA. One of the Hearing Officer’s Findings and Conclusion was that the air quality relating to impacts of SO2 emissions is being adequately protected and that at 2002-2003 SO2 emission levels the relevant Class I increments are not violated.

          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 Utility has begun an information collection program for the Hoot Lake Plant cooling water intake structure. A final determination of compliance with the standards cannot be made until the information collection program has concluded. The Utility believes that the compliance costs will not be material.

          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 either been issued or are under renewal for the Coyote Station, the Big Stone Plant and the Hoot Lake Plant.

          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. The Utility provided a revised focus feasibility study for remediation alternatives to the MPCA in October 2004. The Utility and the MPCA have reached an agreement identifying the remediation technology and completed a portion of the remediation construction in 2005. The preliminary estimate of remediation costs to address the remaining ash disposal site issues over the next two 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. To date, the Utility has incurred no significant costs as a result of these laws. The future 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.

          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 2005, approximately $30.5 million was invested for additions and replacements to its electric utility properties. During the five years ended December 31, 2005 gross electric property additions, including construction work in progress, were approximately $175.2 million and gross retirements were approximately $57.9 million.

          The Utility estimates that during the five-year period 2006-2010 it will invest approximately $381.3 million for electric construction, which includes $247 million for its share of expected expenditures for construction of the planned Big Stone II electric generating plant and related transmission assets if all necessary permits and approvals are granted on a timely basis. The remainder of the 2006-2010 capital budget is primarily for upgrades and extensions to the Utility’s transmission and distribution system.

Franchises

          At December 31, 2005 the Utility had franchises to operate as an electric utility in all 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. The Utility believes that its franchises will be renewed prior to expiration.

Employees

          At December 31, 2005 the Utility had approximately 645 equivalent full-time employees. A total of 433 employees are represented by local unions of the International Brotherhood of Electrical Workers. These labor contracts were renewed in the fall of 2005 and have expiration dates in the fall of 2008 and 2009. 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 consist of businesses producing polyvinyl chloride (PVC) and polyethylene (PE) pipe. The Company derived 15%, 13% and 12% of its consolidated operating revenues for each of the three years ended December 31, 2005, 2004 and 2003, respectively. The Company derived 26%, 14% and 5% of its consolidated income from continuing operations from the Plastics segment for each of the three years ended December 31, 2005, 2004 and 2003, respectively.

          The following is a brief description of these businesses:

Northern Pipe Products, Inc., located in Fargo, North Dakota, 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. Production facilities for PVC pipe are located in Fargo, North Dakota and Hampton, Iowa. The production facility for PE pipe is located in Hampton, Iowa.

Vinyltech Corporation, located in Phoenix, Arizona, 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 220 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 fragmented and competitive, due to the large number of producers, the small 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. The principal areas of competition are a combination of price, service, warranty and product performance. 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 several 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. Two vendors provided approximately 97% and 98% of total resin purchases in 2005 and 2004, respectively. The supply of PVC resin may also be limited due to manufacturing capacity and the limited availability of raw material components. A majority of U.S. resin production plants are located in the Gulf Coast region, which is subject to risk of damage to the plants and potential shutdown of resin production because of exposure to hurricanes that occur in that part of the United States. 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 2005, capital expenditures of approximately $3.6 million were made in the Plastics segment. Total capital expenditures for the five-year period 2006-2010 are estimated to be approximately $18 million. Estimated capital expenditures include approximately $8 million for an expansion at Vinyltech to add a state-of-the-art blending system and two additional extrusion lines which are expected to increase plant capacity by 40% when operational in 2007.

Employees

          At December 31, 2005 the Plastics segment had approximately 191 full-time employees.

MANUFACTURING

General

          Manufacturing consists of businesses engaged in the following activities: production of waterfront equipment; wind towers; material and handling trays and horticultural containers; contract machining and metal parts stamping and fabrication.

          The Company derived 23%, 24% and 22% of its consolidated operating revenues for each of the three years ended December 31, 2005, 2004 and 2003, respectively. The Company derived 14%, 19% and 12% of its consolidated income from continuing operations from the Manufacturing segment for each of the three years ended December 31, 2005, 2004 and 2003, respectively. The following is a brief description of each of these businesses:

BTD Manufacturing, Inc. (BTD), with headquarters located in Detroit Lakes, Minnesota, 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. On January 3, 2005 BTD acquired the assets of Performance Tool & Die Inc., a manufacturer of mid to large progressive dies located in Lakeville, Minnesota, for $4.1 million. BTD has manufacturing facilities in Detroit Lakes, Pelican Rapids and Lakeville, Minnesota.

DMI Industries, Inc., located in West Fargo, North Dakota, engineers and manufactures wind towers and other heavy metal fabricated products. In October, 2005 DMI announced plans for a second manufacturing facility in Fort Erie, Ontario, Canada. The plant is expected to be operational by mid-2006. As a result of this expansion, DMI established a wholly-owned subsidiary, DMI Canada, Inc., for the new Canadian operations.

ShoreMaster, Inc., with headquarters in Fergus Falls, Minnesota, produces residential and commercial waterfront equipment, ranging from boatlifts and docks to full marina systems that are marketed throughout the United States. On January 3, 2005 ShoreMaster acquired the stock of Shoreline Industries, Inc., a manufacturer of boat lift motors located in Pine River, Minnesota for $2.4 million. On May 31, 2005 ShoreMaster acquired the assets of Southeast Floating Docks, Inc., a manufacturer and installer of custom concrete floating dock systems for marinas located in

St. Augustine, Florida, for $4.0 million. ShoreMaster has two wholly-owned subsidiaries, Galva Foam Marine Industries, Inc. and Shoreline Industries, Inc. With the 2005 acquisitions, ShoreMaster has manufacturing facilities located in Fergus Falls and Pine River, Minnesota; Adelanto, California; Camdenton, Missouri; and St. Augustine, Florida.

T. O. Plastics, Inc., located in Minneapolis and Clearwater, Minnesota; and Hampton, South Carolina; 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 from both foreign and domestic manufacturers. 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 high-performance products, innovative technologies, cost-effective manufacturing techniques, close customer relations and support, and increasing product offerings.

          Some of the products sold by the companies in the Manufacturing segment are purchased by companies in the recreational vehicle and wind energy markets. A downturn in these markets could have an adverse impact on the financial results of the Company’s Manufacturing segment.

Steel Supply

          Many of companies in the Manufacturing segment use 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 demand for wind towers that are manufactured by DMI Industries depends substantially on the existence of a federal production tax credit for wind energy. In August 2005, federal legislation extended the production tax credit through 2007. If the production tax credit is not extended beyond 2007, DMI Industries could be adversely affected.

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 2005, capital expenditures of approximately $16.1 million were made in the Manufacturing segment. Total capital expenditures for the Manufacturing segment during the five-year period 2006-2010 are estimated to be approximately $55 million including approximately $4 million for DMI Industries’ new manufacturing facility in Ontario, Canada.

Employees

          At December 31, 2005 the Manufacturing segment had approximately 1,280 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 equipment maintenance, diagnostic imaging services, and rental of diagnostic medical imaging equipment.

          The Company derived 12%, 13% and 14% of its consolidated operating revenues for each of the three years ended December 31, 2005, 2004 and 2003, respectively. The Company derived 8%, 7% and 7% of its consolidated income from continuing operations from the Health Services segment for each of the three years ended December 31, 2005, 2004 and 2003, respectively. The companies comprising the DMS Health Group that deliver diagnostic imaging and healthcare solutions across the United States include:

DMS Health Technologies, Inc. (DMSHT), located in Fargo, North Dakota, sells and services diagnostic medical imaging equipment, patient monitoring equipment and related supplies and accessories. DMSHT sells radiology equipment primarily manufactured by Philips Medical Systems (Philips), a large multi-national company based in the Netherlands. Philips manufactures fluoroscopic, radiographic and vascular equipment, along with ultrasound, computerized tomography (CT), magnetic resonance imaging (MR), positron emission tomography (PET), PET/CT and cardiac cath labs. The dealership agreement with Philips can be terminated on 180 days written notice by either party for any reason and can be terminated by Philips if certain compliance requirements are not met. DMSHT is also a supplier of medical film and related accessories. DMSHT markets mainly to hospitals, clinics and mobile imaging service companies.

DMS Imaging, Inc., a subsidiary of DMSHT located in Fargo, North Dakota, operates diagnostic medical imaging equipment, including CT, MRI, PET and PET/CT and provides nuclear medicine and other similar radiology services to hospitals, clinics, long-term care facilities and other medical providers. Regional offices are located in Houston, Texas; Minneapolis, Minnesota; and Sioux Falls, South Dakota. DMS Imaging provides services through four different business units:

	•		DMS Imaging – provides shared diagnostic medical imaging services (primarily mobile) for MR, CT, nuclear medicine, PET, PET/CT, ultrasound, mammography and bone density analysis.
	•		DMS Interim Solutions – offers interim and rental options for diagnostic imaging services.
	•		DMS MedSource Partners – develops long-term relationships with healthcare providers to offer dedicated in-house diagnostic imaging services.
	•		DMS Portable X-Ray – delivers portable x-ray, ultrasound and electrocardiography 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 expansion or addition of facilities and services.

          The federal Anti-Kickback Statute 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 Statute can include both criminal and civil sanctions as well as possible exclusion from participating in Medicare and other federal healthcare programs. By regulation, the U.S. Department of Health and Human Services has created certain “safe harbors” under the Act. These safe harbors 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 (Stark Law) prohibits a physician from making referrals for certain designated health services payable under Medicare, including services provided by the Health Services companies, to an entity with which the physician has a financial relationship, unless certain exceptions apply. The Stark Law also prohibits an entity from billing for designated health services pursuant to a prohibited referral. A person who engages in a scheme to violate the Stark Law or a person who presents a claim to Medicare in violation of the Stark Law may be subject to civil fines and possible exclusion from participation in federal healthcare programs.

          Some federal courts have held that a violation of the Anti-Kickback Statute or the Stark Law can serve as the basis for a claim under the Federal False Claims Act. A suit under the Federal False Claims Act can be brought directly by the United States Department of Justice, or can be brought by a “whistleblower.” A whistleblower brings suit on behalf of themselves and the United States, and the whistleblower is awarded a percentage of any recovery.

          Recent enforcement actions and media articles regarding relationships among physicians and providers of imaging services have highlighted the importance of compliance with the Anti-Kickback Statute and the Stark Law. The Health Services companies believe their operations comply with the Anti-Kickback Statute and the Stark Law. 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.

          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. 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 the provision 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.

          Additional federal and state regulations that the Health Services companies are subject to include state laws that prohibit the practice of medicine by non-physicians and prohibit fee-splitting arrangements involving physicians; federal Food and Drug Administration requirements; state licensing and certification requirements and federal and state laws governing diagnostic imaging and therapeutic equipment. Courts and regulatory authorities have not fully interpreted a significant number of the current laws and regulations.

          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 significant revenue from direct billings to customers and third-party payors such as Medicare, Medicaid, managed care and private health insurance companies. The Health Services’ customers are primarily healthcare providers who receive the majority of their payments from third-party payors. Payments by third-party payors to such healthcare providers depend, in part, upon their patients’ health insurance policies.

          Beginning in 2006, new Medicare regulations reduce Medicare reimbursement for certain imaging services performed on contiguous body parts during the same day. In addition, the Deficit Reduction Act of 2006 (the DRA) limits reimbursement for imaging services provided in physician offices and in free-standing imaging centers to the reimbursement amount for that same service when provided in a hospital outpatient department. This DRA provision impacts a small number of imaging services. Federal and state legislatures may seek additional cuts in Medicare and Medicaid programs that could impact the value of the services provided by the Health Services segment.

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 providers of items and services similar to those offered by the Health Services companies, the companies within Health Services compete with free-standing imaging centers and health care providers that have their own diagnostic imaging systems, as well as with equipment manufacturers that sell imaging equipment directly to healthcare providers for permanent installation. Some of the direct competitors, which provide contract MR and PET/CT 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, rather than obtain the services from the Health Services company. The Health Services companies may also experience greater

competition in states that currently have certificate of need laws if such laws were repealed, thereby reducing barriers to entry and competition in that state. The Health Services companies compete against other similar 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

           PET, PET/CT and nuclear medicine 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.

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	OTTER TAIL CORPORATION
	By /s/ Kevin G. Moug
	Kevin G. Moug
	Chief Financial Officer and Treasurer
Dated:	March 14, 2006

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*		Management contract or compensatory plan or arrangement required to be filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K.

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