10-K

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:

2005 Annual Report to Shareholders-Portions incorporated by reference into Parts I and II
Proxy Statement dated March 6, 2006-Portions incorporated by reference into Part III

TABLE OF CONTENTS

PART I
	Item 1. BUSINESS
	Item 1A. RISK FACTORS
	Item 1B. UNRESOLVED STAFF COMMENTS
	Item 2. PROPERTIES
	Item 3. LEGAL PROCEEDINGS
	Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
	Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 2006)
PART II
	Item 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
	Item 6. SELECTED FINANCIAL DATA
	Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
	Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
	Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
	Item 9A. CONTROLS AND PROCEDURES
	Item 9B. OTHER INFORMATION
PART III
	Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
	Item 11. EXECUTIVE COMPENSATION
	Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
	Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
	Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
	Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
SIGNATURES
Form of Stock Option Agreement
Form of Restricted Stock Agreement
Portions of 2005 Annual Report to Shareholders
Subsidiaries of Registrant
Consent of Deloitte & Touche LLP
Powers of Attorney
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

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.

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          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.

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          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.

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          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.

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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.

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          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

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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	%

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          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.

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     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.

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          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.

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          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:

• 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.

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• 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.

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          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.

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          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.

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          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.

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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.

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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.

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          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

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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.

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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.

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          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.

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          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

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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.

Capital Expenditures

          Capital expenditures in this segment principally relate to the acquisition of diagnostic imaging equipment used in the imaging business. During 2005, capital expenditures of approximately $3.1 million were made in the Health Services segment. Total capital expenditures during the five-year period 2006-2010 are estimated to be approximately $3 million. Operating leases are also used to finance the acquisition of medical equipment used by Health Services companies. In 2005, the Health Services companies entered into new operating leases for equipment totaling approximately $65 million. Current operating lease commitments during the five-year period 2006-2010 are estimated to be $115 million.

Employees

          At December 31, 2005 the Health Services segment had approximately 422 full-time employees.

FOOD INGREDIENT PROCESSING

General

          Food ingredient processing consists of Idaho Pacific Holdings, Inc. (IPH), which was acquired by the Company on August 18, 2004. IPH, headquartered in Ririe, Idaho, manufactures and supplies dehydrated potato products to food manufacturers in the snack food, foodservice and bakery industries. IPH has three processing facilities located in Ririe, Idaho; Center, Colorado; and Souris, Prince Edward Island, Canada. Together these three facilities have the capacity to process approximately 114 million pounds of potatoes.

          The Company derived 4% and 2% of its consolidated operating revenues for each of the years ended December 31, 2005 and 2004, respectively. The Company derived 1% of its consolidated income from continuing operations from the Food Ingredient Processing segment for 2005.

Customers

     IPH sells to customers in the United States, Mexico and Canada and exports products to Europe, the Middle East, the Pacific Rim and Central America. Products are sold through company sales persons and broker sales representatives. Customers include end users in the food ingredient industries and distributors to the food ingredient industries and foodservice industries, both domestically and internationally.

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Competition

          The market for processed, dehydrated potato flakes, flour and granules is highly competitive. The ability to compete depends on superior product quality, competitive product pricing and strong customer relationships. IPH competes with numerous manufacturers and dehydrators of varying sizes in the United States, including companies with greater financial resources.

Potato Supply

          The principal raw material used by IPH is off-grade potatoes from fresh packing operations and growers. These potatoes are unsuitable for use in other markets due to imperfections. They do not meet United States Department of Agriculture’s general requirements and expectations for size, shape or color. While IPH has processing capabilities in three geographically distinct growing regions, there can be no assurance it will be able to obtain raw materials due to poor growing conditions, a loss of key growers and other factors. A loss of raw materials or the necessity of paying much higher prices for raw materials could adversely affect the financial performance of IPH.

Regulations

          IPH is regulated by the United States Department of Agriculture and the Federal Food and Drug Administration and other federal, state, local and foreign governmental agencies relating to the quality of products, sanitation, safety and environmental control. IPH adheres to strict manufacturing practices that dictate sanitary conditions conducive to a high quality food product. All facilities use wastewater systems that are regulated by government environmental agencies in their respective locations and are subject to permitting by these agencies. IPH believes that it complies with applicable laws and regulations in all material respects, and that continued compliance with such laws and regulations will not have a material effect on its capital expenditures, earnings or competitive position.

Capital Expenditures

          Capital expenditures in the Food Ingredient Processing segment typically include additional investments in new dehydration equipment or expenditures to replace worn-out 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 $3.0 million were made in the Food Ingredient Processing segment. Total capital expenditures for the Food Ingredient Processing segment during the five-year period 2006-2010 are estimated to be approximately $15 million.

Employees

          At December 31, 2005 the Food Ingredient Processing segment had approximately 301 full-time employees.

OTHER BUSINESS OPERATIONS

General

     Other Business Operations consists of businesses involved in residential, commercial and industrial electric contracting industries; fiber optic and electric distribution systems; wastewater, water and HVAC systems construction; transportation; energy services and natural gas marketing and the portion of corporate general and administrative expenses that are not allocated to the other segments.

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          The Company derived 16%, 17% and 15% of its consolidated operating revenues for each of the years ended December 31, 2005, 2004 and 2003, respectively. Due primarily to the inclusion of the unallocated corporate general and administrative expenses, this segment’s contribution to consolidated income from continuing operations for each of three years ended December 31, 2005, 2004 and 2003 was (20%), (18%) and (13%), respectively. Following is a brief description of the businesses included in this segment.

Foley Company, headquartered in Kansas City, Missouri, provides mechanical and prime contracting services for water and wastewater treatment plants, power generation plants, hospital and pharmaceutical facilities, and other industrial and manufacturing projects across a multi-state service area in the Central United States.

Midwest Construction Services, Inc., located in Moorhead, Minnesota, is a holding company for five subsidiaries that provide security products, electrical design and construction services for the industrial, commercial and municipal business markets, including government, institutional, communications, utility and renewable energy projects primarily in the Upper Midwest.

Otter Tail Energy Services Company, headquartered in Fergus Falls, Minnesota, provides technical and engineering services, energy efficient lighting and retail marketing of natural gas and energy management services in Iowa, South Dakota, North Dakota and Minnesota.

E. W. Wylie Corporation (Wylie), located in Fargo, North Dakota, is a contract and common carrier operating a fleet of tractors and trailers in 48 states and 6 Canadian provinces. Wylie has trucking terminals in Fargo, North Dakota; Des Moines, Iowa; Fort Worth, Texas and Chicago, Illinois.

Competition

          Each of the businesses in Other Business Operations is subject to competition, as well as the effects of general economic conditions in their respective industries. The construction companies in this segment must compete with other construction companies in the Upper Midwest and the Central regions of the United States, including companies with greater financial resources, when bidding on new projects. The Company believes the principal competitive factors in the construction segment are price, quality of work and customer services.

          The trucking industry, in which Wylie competes, is highly competitive. Wylie competes primarily with other short- to medium-haul, flatbed truckload carriers, internal shipping conducted by existing and potential customers and, to a lesser extent, railroads. Competition for the freight transported by Wylie is based primarily on service and efficiency and to a lesser degree, on freight rates. There are other trucking companies that have greater financial resources, operate more equipment or carry a larger volume of freight than Wylie and these companies compete with Wylie for qualified drivers.

Capital Expenditures

          Capital expenditures in this segment typically include investments in additional trucks, flatbed trailers and construction equipment. During 2005, capital expenditures of approximately $3.7 million were made in Other Business Operations. Capital expenditures during the five-year period 2006-2010 are estimated to be approximately $5 million for Other Business Operations.

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Employees

          At December 31, 2005 there were approximately 420 full-time employees in Other Business Operations. Moorhead Electric, Inc., a subsidiary of Midwest Construction Services, Inc., has 111 employees represented by a local union of the International Brotherhood of Electrical Workers and covered by a labor contract that expires on May 31, 2007. Foley Company has 92 employees represented by various unions, including Boilermakers, Carpenters and Millwrights, Cement Masons, Operating Engineers, Pipe Fitters and Plumbers and Teamsters. Foley has several labor contracts with various expiration dates in 2006 and 2007. Moorhead Electric, Inc. and Foley Company have not experienced any strike, work stoppage or strike vote, and consider their present relations with employees to be good.

Forward-Looking Information — Safe Harbor Statement Under the
Private Securities Litigation Reform Act of 1995

This Annual Report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 (the Act). When used in this Form 10-K and in future filings by the Company with the Securities and Exchange Commission, in the Company’s press releases and in oral statements, words such as “may,” “will,” “expect,” “anticipate,” “continue,” “estimate,” “project,” “believes” or similar expressions are intended to identify forward-looking statements within the meaning of the Act. Such statements are based on current expectations and assumptions, and entail various risks and uncertainties that could cause actual results to differ materially from those expressed in such forward- looking statements.

          The following factors, among others, could cause actual results for the Company to differ materially from those discussed in the forward-looking statements:

• The Company is subject to government regulations and actions that may have a negative impact on its business and results of operations.

• Weather conditions can adversely affect the Company’s operations and revenues.

• Electric wholesale margins could be reduced as the MISO market becomes more efficient.

• Electric wholesale trading margins could be reduced or eliminated by losses due to trading activities.

• Federal and state environmental regulation could cause the Company to incur substantial capital expenditures which could result in increased operating costs.

• The Company’s plans to grow and diversify through acquisitions may not be successful and could result in poor financial performance.

• Competition is a factor in all of the Company’s businesses.

• Economic uncertainty could have a negative impact on the Company’s future revenues and earnings.

• Volatile financial markets could restrict the Company’s ability to access capital and could increase borrowing costs and pension plan expenses.

• The Company’s Food Ingredient Processing segment is dependent on adequate sources of raw materials for processing. Should the supply of these raw materials be affected by poor growing conditions, this could negatively impact the results of operations for this segment. This segment could also be impacted by foreign currency changes between Canadian and United States currency and prices of natural gas.

• The Company’s Plastics segment is highly dependent on a limited number of vendors for PVC resin, many of which are located in the Gulf Coast region. The loss of a key vendor or an interruption or delay in the supply of PVC resin could result in reduced sales or increased costs for this segment.

• The Company’s Health Services businesses may not be able to retain or comply with the dealership arrangement and other agreements with Philips Medical.

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A further discussion of risk factors and cautionary statements is set forth under “Risk Factors and Cautionary Statements” and “Critical Accounting Policies Involving Significant Estimates” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” on pages 26 through 32 of the Company’s 2005 Annual Report to Shareholders, filed as an Exhibit hereto. These factors are in addition to any other cautionary statements, written or oral, which may be made or referred to in connection with any forward-looking statement or contained in any subsequent filings by the Company with the Securities and Exchange Commission. The Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

Item 1A. RISK FACTORS

          The information required by this Item is incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Factors and Cautionary Statements” on Pages 26 through 30 of the Company’s 2005 Annual Report to Shareholders, filed as an Exhibit hereto.

Item 1B. UNRESOLVED STAFF COMMENTS

          None.

Item 2. PROPERTIES

          The Coyote Station, which commenced operation in 1981, is a 414,000 kw (nameplate rating) mine-mouth plant located in the lignite coal fields near Beulah, North Dakota and is jointly owned by the Utility, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern Public Service Company. The Utility is the operating agent of the Coyote Station and owns 35% of the plant.

          The Utility, jointly with Northwestern Public Service Company and Montana-Dakota Utilities Co., owns the 414,000 kw (nameplate rating) Big Stone Plant in northeastern South Dakota which commenced operation in 1975. The Utility is the operating agent of Big Stone Plant and owns 53.9% of the plant.

          Located near Fergus Falls, Minnesota, the Hoot Lake Plant is comprised of three separate generating units with a combined nameplate rating of 127,000 kw. The oldest Hoot Lake Plant generating unit was constructed in 1948 (7,500 kw nameplate rating) and was retired on December 31, 2005. A second unit was added in 1959 (53,500 kw nameplate rating) and a third unit was added in 1964 (66,000 kw nameplate rating) and modified in 1988 to provide cycling capability, allowing this unit to be more efficiently brought online from a standby mode.

          As of December 31, 2005 the Utility’s transmission facilities, which are interconnected with lines of other public utilities, consisted of 48 miles of 345 kv lines; 405 miles of 230 kv lines; 799 miles of 115 kv lines; and 4,044 miles of lower voltage lines, principally 41.6 kv. The Utility owns the uprated portion of the 48 miles of the 345 kv line, with Minnkota Power Cooperative retaining title to the original 230 kv construction.

          In addition to the properties mentioned above, the Company owns and has investments in offices and service buildings. The Company’s subsidiaries own facilities and equipment used to manufacture PVC pipe, produce dehydrated potato products and perform metal stamping, fabricating and contract machining; construction equipment and tools; medical imaging equipment and a fleet of flatbed trucks and trailers.

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          Management of the Company believes the facilities and equipment described above are adequate for the Company’s present businesses.

          All of the common shares of the companies owned by Varistar are pledged to secure indebtedness of Varistar.

Item 3. LEGAL PROCEEDINGS

          The Company is the subject of various pending or threatened legal actions and proceedings in the ordinary course of its business. Such matters are subject to many uncertainties and to outcomes that are not predictable with assurance. The Company records a liability in its consolidated financial statements for costs related to claims, including future legal costs, settlements and judgments, where it has assessed that a loss is probable and an amount can be reasonably estimated. The Company believes the final resolution of currently pending or threatened legal actions and proceedings, either individually or in the aggregate, will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

          No matters were submitted to a vote of security holders during the three months ended December 31, 2005.

Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 2006)

          Set forth below is a summary of the principal occupations and business experience during the past five years of the executive officers as defined by rules of the Securities and Exchange Commission. Except as noted below, each of the executive officers has been employed by the Company for more than five years in an executive or management position either with the Company or its wholly-owned subsidiary, Varistar.

	DATES ELECTED
NAME AND AGE	TO OFFICE	PRESENT POSITION AND BUSINESS EXPERIENCE
John D. Erickson (47)	4/8/02	Present:	President and Chief Executive Officer
	4/9/01	President
	Prior to
	4/9/01	Executive Vice President, Chief Financial Officer and Treasurer
George A. Koeck (53)	4/10/00	Present:	Corporate Secretary and General Counsel

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	DATES ELECTED
NAME AND AGE	TO OFFICE	PRESENT POSITION AND BUSINESS EXPERIENCE
Lauris N. Molbert (48)	6/10/02	Present: Executive Vice President and Chief Operating Officer
	4/9/01	Executive Vice President, Corporate Development and Varistar President and Chief Operating Officer
	Prior to
	4/9/01	Vice President, Chief Operating Officer, Varistar
Kevin G. Moug (46)	4/9/01	Present: Chief Financial Officer and Treasurer
	Prior to
	4/9/01	Varistar Chief Financial Officer and Treasurer
Charles S. MacFarlane (41)	5/1/03	President, Otter Tail Power Company
	6/1/02	Interim President, Otter Tail Power Company
	1/29/02	Director, Finance & Strategic Planning, Otter Tail Power Company
	12/1/01	Director, Finance Planning, Otter Tail Power Company
	Prior to
	12/2/01	Director, Electric Distribution Planning, Engineering & Reliability, Xcel Energy

          With the exception of Charles S. MacFarlane, the term of office for each of the executive officers is one year and any executive officer elected may be removed by the vote of the Board of Directors at any time during the term. Mr. MacFarlane is not appointed by the Board of Directors. Mr. MacFarlane is a son of John MacFarlane, who is the Chairman of the Board of Directors. There are no other family relationships between any of the executive officers.

PART II

Item 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

          The information required by this Item is incorporated by reference to the first sentence under “Otter Tail Corporation Stock Listing” on Page 60, to “Selected Consolidated Financial Data” on Page 17 and to “Quarterly Information” on Page 57 of the Company’s 2005 Annual Report to Shareholders, filed as an Exhibit hereto. The Company did not repurchase any equity securities during the three months ended December 31, 2005.

Item 6. SELECTED FINANCIAL DATA

          The information required by this Item is incorporated by reference to “Selected Consolidated Financial Data” on Page 17 of the Company’s 2005 Annual Report to Shareholders, filed as an Exhibit hereto.

31

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

          The information required by this Item is incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” on Pages 18 through 33 of the Company’s 2005 Annual Report to Shareholders, filed as an Exhibit hereto.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

          The information required by this Item is incorporated by reference to “Quantitative and Qualitative Disclosures About Market Risk” on Pages 28 through 30 of the Company’s 2005 Annual Report to Shareholders, filed as an Exhibit hereto.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

          The information required by this Item is incorporated by reference to “Quarterly Information” on Page 57, the Company’s audited financial statements on Pages 35 through 57 and “Report of Independent Registered Public Accounting Firm” on page 34 of the Company’s 2005 Annual Report to Shareholders, filed as an Exhibit hereto.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

          None.

Item 9A. CONTROLS AND PROCEDURES

          Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act)) as of December 31, 2005, the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2005.

          The Company’s management included IPH, acquired in August 2004, in its assessment of the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2005. IPH was not included in management’s assessment of the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2004 based on guidelines established by the Securities and Exchange Commission that allow newly acquired companies to be excluded from assessment in the year they are acquired. Apart from this change, there have not been any other changes in the Company’s internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, the Company’s internal controls over financial reporting.

          The annual report of the Company’s management on internal control over financial reporting is incorporated by reference to “Management’s Report Regarding Internal Controls Over Financial Reporting” on Page 33 of the Company’s 2005 Annual Report to Shareholders, filed as an Exhibit hereto. The attestation report of Deloitte & Touche LLP, the Company’s independent registered public accounting firm, regarding the Company’s internal control over financial reporting is incorporated by reference to “Report of Independent Registered Public Accounting Firm” on Page 34 of the Company’s 2005 Annual Report to Shareholders, filed as an Exhibit hereto.

32

Item 9B. OTHER INFORMATION

          None.

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

          The information required by this Item regarding Directors is incorporated by reference to the information under “Election of Directors” in the Company’s definitive Proxy Statement dated March 6, 2006. The information regarding executive officers is set forth in Item 4A hereto. The information regarding Section 16 reporting is incorporated by reference to the information under “Management’s Security Ownership — Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive Proxy Statement dated March 6, 2006. The information regarding Audit Committee financial experts is incorporated by reference to the information under “Meetings and Committees of the Board – Audit Committee” in the Company’s definitive Proxy Statement dated March 6, 2006.

          The Company has adopted a code of conduct that applies to all of its directors, officers (including its principal executive officer, principal financial officer, principal accounting officer or controller or person performing similar functions) and employees. The Company’s code of conduct is available on its website at www.ottertail.com. The Company intends to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of its code of conduct by posting such information on its website at the address specified above. Information on the Company’s website is not deemed to be incorporated by reference into this Annual Report on Form 10-K.

Item 11. EXECUTIVE COMPENSATION

          The information required by this Item is incorporated by reference to the information under “Executive Compensation — Summary Compensation Table,” “Executive Compensation — Options/SAR Grants in Last Fiscal Year,” “Executive Compensation — Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal Year-End Option/SAR Values,” “Executive Compensation — Long-Term Incentive Plan Awards in Last Fiscal Year,” “Executive Compensation — Pension and Supplemental Retirement Plans,” “Executive Compensation — Severance and Employment Agreements” and “Director Compensation” in the Company’s definitive Proxy Statement dated March 6, 2006.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

          The information required by this Item regarding security ownership is incorporated by reference to the information under “Outstanding Voting Shares” and “Management’s Security Ownership” in the Company’s definitive Proxy Statement dated March 6, 2006.

          The information required by this Item regarding equity compensation plans is incorporated by reference to the information under “Proposal to Amend the 1999 Employee Stock Purchase Plan - Equity Compensation Plan Information” in the Company’s definitive Proxy Statement dated March 6, 2006.

33

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

          None.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

          The information required by this Item is incorporated by reference to the information under “Ratification of Independent Registered Public Accounting Firm — Fees” and “Ratification of Independent Registered Public Accounting Firm – Pre-approval of Audit/Non-Audit Services Policy” in the Company’s definitive Proxy Statement dated March 6, 2006.

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) List of documents filed:

(1)	and (2) See Table of Contents on Page 36 hereof.
(3)	See Exhibit Index on Pages 37 through 43 hereof.

Pursuant to Item 601(b)(4)(iii) of Regulation S-K, copies of certain instruments defining the rights of holders of certain long-term debt of the Company are not filed, and in lieu thereof, the Company agrees to furnish copies thereof to the Securities and Exchange Commission upon request.

34

SIGNATURES

          Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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

          Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature and Title

John D. Erickson	)
President and Chief Executive Officer	)
(principal executive officer)	)
	)
Kevin G. Moug	)
Chief Financial Officer and Treasurer	)
(principal financial and accounting officer)	)
	)	By	/s/ John D. Erickson
John C. MacFarlane	)		John D. Erickson
Chairman of the Board and Director	)		Pro Se and Attorney-in-Fact
	)		Dated March 14, 2006
Karen M. Bohn, Director	)
	)
Thomas M. Brown, Director	)
	)
Dennis R. Emmen, Director	)
	)
Arvid R. Liebe, Director	)
	)
Kenneth L. Nelson, Director	)
	)
Nathan I. Partain, Director	)
	)
Gary J. Spies, Director	)
	)
Robert N. Spolum, Director	)

35

OTTER TAIL CORPORATION

TABLE OF CONTENTS

FINANCIAL STATEMENTS, SUPPLEMENTARY FINANCIAL DATA, SUPPLEMENTAL FINANCIAL SCHEDULES INCLUDED IN
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2005

          The following items are incorporated in this Annual Report on Form 10-K by reference to the registrant’s Annual Report to Shareholders for the year ended December 31, 2005 filed as an Exhibit hereto:

	Page in
	Annual
	Report to
	Shareholders
Financial Statements:
Management’s Report Regarding Internal Controls Over Financial Reporting	33
Report of Independent Registered Public Accounting Firm	34
Consolidated Statements of Income for the Three Years Ended December 31, 2005	35
Consolidated Balance Sheets, December 31, 2005 and 2004	36&37
Consolidated Statements of Common Shareholders’ Equity for the Three Years Ended December 31, 2005	38
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 2005	39
Consolidated Statements of Capitalization, December 31, 2005 and 2004	40
Notes to Consolidated Financial Statements	41-57
Selected Consolidated Financial Data for the Five Years Ended December 31, 2005	17
Quarterly Data for the Two Years Ended December 31, 2005	57

Schedules are omitted because of the absence of the conditions under which they are required, because the amounts are insignificant or because the information required is included in the financial statements or the notes thereto.

36

Exhibit Index
to
Annual Report
on Form 10-K
For Year Ended December 31, 2005

	Previously Filed
		As
		Exhibit
	File No.	No.
3-A	8-K filed 4/10/01		3	—Restated Articles of Incorporation, as amended (including resolutions creating outstanding series of Cumulative Preferred Shares).
3-C	33-46071		4-B	—Bylaws as amended through April 11, 1988.
4-D-1	8-A dated 1/28/97		1	—Rights Agreement, dated as of January 28, 1997 (the Rights Agreement), between the Company and Norwest Bank Minnesota, National Association.
4-D-2	8-A/A dated 9/29/98		1	—Amendment No. 1, dated as of August 24, 1998, to the Rights Agreement.
4-D-3	10-K for year ended 12/31/01		4-D-7	—Note Purchase Agreement dated as of December 1, 2001.
4-D-4	10-K for year ended 12/31/02		4-D-4	—First Amendment dated as of December 1, 2002 to Note Purchase Agreement dated as of December 1, 2001.
4-D-5	10-Q for quarter ended 9/30/04		4.2	—Second Amendment dated as of October 1, 2004 to Note Purchase Agreement dated as of December 1, 2001.
4-D-6	8-K filed 05/03/05		4.1	—Credit Agreement dated as of April 27, 2005 among the Company, the Lenders named therein, JP Morgan Chase Bank N.A., as Syndication Agent, Wells Fargo Bank, National Association, as Documentation Agent, and U.S. Bank National Association, as Agent and Lead Arranger.
10-A	2-39794		4-C	—Integrated Transmission Agreement dated August 25, 1967, between Cooperative Power Association and the Company.
10-A-1	10-K for year ended 12/31/92		10-A-1	—Amendment No. 1, dated as of September 6, 1979, to Integrated Transmission Agreement, dated as of August 25, 1967, between Cooperative Power Association and the Company.

-37-

	Previously Filed
		As
		Exhibit
	File No.	No.
10-A-2	10-K for year ended 12/31/92	10-A-2	—Amendment No. 2, dated as of November 19, 1986, to Integrated Transmission Agreement between Cooperative Power Association and the Company.
10-C-1	2-55813	5-E	—Contract dated July 1, 1958, between Central Power Electric Corporation, Inc., and the Company.
10-C-2	2-55813	5-E-1	—Supplement Seven dated November 21, 1973. (Supplements Nos. One through Six have been superseded and are no longer in effect.)
10-C-3	2-55813	5-E-2	—Amendment No. 1 dated December 19, 1973, to Supplement Seven.
10-C-4	10-K for year ended 12/31/91	10-C-4	—Amendment No. 2 dated June 17, 1986, to Supplement Seven.
10-C-5	10-K for year ended 12/31/92	10-C-5	—Amendment No. 3 dated June 18, 1992, to Supplement Seven.
10-C-6	10-K for year ended 12/31/93	10-C-6	—Amendment No. 4 dated January 18, 1994 to Supplement Seven.
10-D	2-55813	5-F	—Contract dated April 12, 1973, between the Bureau of Reclamation and the Company.
10-E-1	2-55813	5-G	—Contract dated January 8, 1973, between East River Electric Power Cooperative and the Company.
10-E-2	2-62815	5-E-1	—Supplement One dated February 20, 1978.
10-E-3	10-K for year ended 12/31/89	10-E-3	—Supplement Two dated June 10, 1983.
10-E-4	10-K for year ended 12/31/90	10-E-4	—Supplement Three dated June 6, 1985.
10-E-5	10-K for year ended 12/31/92	10-E-5	—Supplement No. Four, dated as of September 10, 1986.
10-E-6	10-K for year ended 12/31/92	10-E-6	—Supplement No. Five, dated as of January 7, 1993.
10-E-7	10-K for year ended 12/31/93	10-E-7	—Supplement No. Six, dated as of December 2, 1993.

-38-

	Previously Filed
		As
		Exhibit
	File No.	No.
10-F	10-K for year ended 12/31/89		10-F	—Agreement for Sharing Ownership of Generating Plant by and between the Company, Montana-Dakota Utilities Co., and Northwestern Public Service Company (dated as of January 7, 1970).
10-F-1	10-K for year ended 12/31/89		10-F-1	—Letter of Intent for purchase of share of Big Stone Plant from Northwestern Public Service Company (dated as of May 8, 1984).
10-F-2	10-K for year ended 12/31/91		10-F-2	—Supplemental Agreement No. 1 to Agreement for Sharing Ownership of Big Stone Plant (dated as of July 1, 1983).
10-F-3	10-K for year ended 12/31/91		10-F-3	—Supplemental Agreement No. 2 to Agreement for Sharing Ownership of Big Stone Plant (dated as of March 1, 1985).
10-F-4	10-K for year ended 12/31/91		10-F-4	—Supplemental Agreement No. 3 to Agreement for Sharing Ownership of Big Stone Plant (dated as of March 31, 1986).
10-F-5	10-Q for quarter ended 9/30/03		10.1	—Supplemental Agreement No. 4 to Agreement for Sharing Ownership of Big Stone Plant (dated as of April 24, 2003).
10-F-6	10-K for year ended 12/31/92		10-F-5	—Amendment I to Letter of Intent dated May 8, 1984, for purchase of share of Big Stone Plant.
10-G	10-Q for quarter ended 06/30/04		10.3	—Master Coal Purchase and Sale Agreement by and between the Company, Montana-Dakota Utilities Co., Northwestern Corporation and Kennecott Coal Sales Company-Big Stone Plant (dated as of June 1, 2004).
10-G-1	10-Q for quarter ended 06/30/04		10.4	—Coal Supply Confirmation Letter by and between the Company, Montana-Dakota Utilities Co., Northwestern Corporation and Kennecott Coal Sales Company for shipments of coal from January 1, 2005 through December 31, 2007 — Big Stone Plant (dated as of July 14, 2004).
10-G-2	10-Q for quarter ended 06/30/04		10.5	—Coal Supply Agreement by and between the Company, Montana-Dakota Utilities Co., Northwestern Corporation and Arch Coal Sales Company, Inc. for the period January 1, 2005 through December 31, 2007 — Big Stone Plant (dated as of July 22, 2004).

-39-

	Previously Filed
		As
		Exhibit
	File No.	No.
10-H	2-61043		5-H	—Agreement for Sharing Ownership of Coyote Station Generating Unit No. 1 by and between the Company, Minnkota Power Cooperative, Inc., Montana-Dakota Utilities Co., Northwestern Public Service Company and Minnesota Power & Light Company (dated as of July 1, 1977).
10-H-1	10-K for year ended 12/31/89		10-H-1	—Supplemental Agreement No. One dated as of November 30, 1978, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.
10-H-2	10-K for year ended 12/31/89		10-H-2	—Supplemental Agreement No. Two dated as of March 1, 1981, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1 and Amendment No. 2 dated March 1, 1981, to Coyote Plant Coal Agreement.
10-H-3	10-K for year ended 12/31/89		10-H-3	—Amendment dated as of July 29, 1983, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.
10-H-4	10-K for year ended 12/31/92		10-H-4	—Agreement dated as of September 5, 1985, containing Amendment No. 3 to Agreement for Sharing Ownership of Coyote Generating Unit No. 1, dated as of July 1, 1977, and Amendment No. 5 to Coyote Plant Coal Agreement, dated as of January 1, 1978.
10-H-5	10-Q for quarter ended 9/30/01		10-A	—Amendment dated as of June 14, 2001, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.
10-H-6	10-Q for quarter ended 9/30/03		10.2	—Amendment dated as of April 24, 2003, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.
10-I	2-63744		5-I	—Coyote Plant Coal Agreement by and between the Company, Minnkota Power Cooperative, Inc., Montana-Dakota Utilities Co., Northwestern Public Service Company, Minnesota Power & Light Company, and Knife River Coal Mining Company (dated as of January 1, 1978).
10-I-1	10-K for year ended 12/31/92		10-I-1	—Addendum, dated as of March 10, 1980, to Coyote Plant Coal Agreement.
10-I-2	10-K for year ended 12/31/92		10-I-2	—Amendment (No. 3), dated as of May 28, 1980, to Coyote Plant Coal Agreement.
10-I-3	10-K for year ended 12/31/92		10-I-3	—Fourth Amendment, dated as of August 19, 1985 to Coyote Plant Coal Agreement.

-40-

	Previously Filed
		As
		Exhibit
	File No.	No.
10-I-4	10-Q for quarter ended 6/30/93		19-A	—Sixth Amendment, dated as of February 17, 1993 to Coyote Plant Coal Agreement.
10-I-5	10-K for year ended 12/31/01		10-I-5	—Agreement and Consent to Assignment of the Coyote Plant Coal Agreement.
10-J	10-Q for quarter ended 06/30/05		10.1	—Big Stone II Power Plant Participation Agreement by and among the Company, 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, as Owners (dated as of June 30, 2005).
10-J-1	10-Q for quarter ended 06/30/05		10.2	—Big Stone II Power Plant Operation & Maintenance Services Agreement by and among the Company, 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, as Owners, and the Company, as Operator (dated as of June 30, 2005).
10-J-2	10-Q for quarter ended 06/30/05		10.3	—Big Stone I and Big Stone II 2005 Joint Facilities Agreement by and among the Company, Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., NorthWestern Corporation dba NorthWestern Energy, Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency, as Owners (dated as of June 30, 2005).
10-K-1	10-Q for quarter ended 9/30/99		10	—Power Sales Agreement between the Company and Manitoba Hydro Electric Board (dated as of July 1, 1999).
10-L	10-K for year ended 12/31/91		10-L	—Integrated Transmission Agreement by and between the Company, Missouri Basin Municipal Power Agency and Western Minnesota Municipal Power Agency (dated as of March 31, 1986).
10-L-1	10-K for year ended 12/31/88		10-L-1	—Amendment No. 1, dated as of December 28, 1988, to Integrated Transmission Agreement (dated as of March 31, 1986).

-41-

	Previously Filed
		As
		Exhibit
	File No.	No.
10-M	10-Q for quarter ended 06/30/04		10.1	—Master Coal Purchase Agreement by and between the Company and Kennecott Coal Sales Company - - Hoot Lake Plant (dated as of December 31, 2001).
10-M-1	10-Q for quarter ended 06/30/04		10.2	—Coal Supply Confirmation Letter by and between the Company and Kennecott Coal Sales Company for shipments of coal from July 1, 2004 through December 31, 2007 — Hoot Lake Plant (dated as of May 26, 2004).
10-N-1	10-K for year ended 12/31/02		10-N-1	—Deferred Compensation Plan for Directors, as amended.*
10-N-2	8-K filed 02/04/05		10.1	—Executive Survivor and Supplemental Retirement Plan (2005 Restatement).*
10-N-3	10-K for year ended 12/31/93		10-N-5	—Nonqualified Profit Sharing Plan.*
10-N-4	10-Q for quarter ended 3/31/02		10-B	—Nonqualified Retirement Savings Plan, as amended.*
10-N-5	10-K for year ended 12/31/98		10-N-6	—1999 Employee Stock Purchase Plan.
10-N-6	10-K for year ended 12/31/98		10-N-7	—1999 Stock Incentive Plan.*
10-N-7				—Form of Stock Option Agreement.*
10-N-8				—Form of Restricted Stock Agreement.*
10-N-9	8-K filed 04/15/05		10.1	—Form of 2005 Performance Award Agreement.*
10-N-10	8-K filed 04/15/05		10.2	—Executive Annual Incentive Plan (Effective April 1, 2005).*
10-O-1	10-Q for quarter ended 6/30/02		10-A	—Executive Employment Agreement, John Erickson.*
10-O-2	10-Q for quarter ended 6/30/02		10-B	—Executive Employment Agreement and amendment no. 1, Lauris Molbert.*

-42-

	Previously Filed
		As
		Exhibit
	File No.	No.
10-O-3	10-Q for quarter ended 6/30/02	10-C	—Executive Employment Agreement, Kevin Moug.*
10-O-4	10-Q for quarter ended 6/30/02	10-D	—Executive Employment Agreement, George Koeck.*
10-P-1	10-Q for quarter ended 6/30/02	10-E	—Change in Control Severance Agreement, John Erickson.*
10-P-2	10-Q for quarter ended 6/30/02	10-F	—Change in Control Severance Agreement, Lauris Molbert.*
10-P-3	10-Q for quarter ended 6/30/02	10-G	—Change in Control Severance Agreement, Kevin Moug.*
10-P-4	10-Q for quarter ended 6/30/02	10-H	—Change in Control Severance Agreement, George Koeck.*
13-A			—Portions of 2005 Annual Report to Shareholders incorporated by reference in this Form 10-K.
21-A			—Subsidiaries of Registrant.
23			—Consent of Deloitte & Touche LLP.
24-A			—Powers of Attorney.
31.1			—Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2			—Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1			—Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2			—Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

-43-

EX-10.N.7 2 c02868exv10wnw7.htm FORM OF STOCK OPTION AGREEMENT

Exhibit 10-N-7

OTTER TAIL CORPORATION
1999 STOCK INCENTIVE PLAN
2005 NONQUALIFIED STOCK OPTION AGREEMENT

     This 2005 Nonqualified Stock Option Agreement between Otter Tail Corporation, a Minnesota corporation (the “Corporation”), and the person named in the attached Stock Option Award Certificate who is an employee of the Corporation or one of its Affiliates (the “Optionee”), effective as of the date of grant set forth in the attached Stock Option Award Certificate (the “Grant Date”).

     WHEREAS, the Corporation desires to provide the Optionee with an opportunity to purchase shares of the Corporation’s Common Stock, par value $5.00 per share (the “Common Shares”), as hereinafter provided in order to carry out the purpose of the Corporation’s 1999 Stock Incentive Plan (the “Plan”).

     WHEREAS, this 2005 Nonqualified Stock Option Agreement applies to all options with a Grant Date of January 2005 and thereafter (the “Effective Date”). No change is intended or made to Options issued prior to the Effective Date.

     NOW, THEREFORE, for good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the Corporation and the Optionee hereby agree as follows:

     1. Grant of Option. The Corporation hereby grants to the Optionee the right and option (the “Option”) to purchase all or any part of the aggregate number of Common Shares set forth in the attached Stock Option Award Certificate, on the terms and conditions set forth in this Agreement and the Plan. The Option granted hereunder shall not be an incentive stock option within the meaning of Section 422 of the Internal Revenue Code of 1986, as amended (the “Code”).

     2. Exercise Price. The per share purchase price of the Common Shares subject to the Option shall be the option price per share set forth in the attached Stock Option Award Certificate.

     3. Duration and Exercisability. The term of the Option shall be for a period of ten years from the Grant Date, terminating at the close of business on the expiration date set forth in the attached Stock Option Award Certificate (the “Expiration Date”) or such shorter period as is prescribed in paragraph 6 hereof. The Option becomes exercisable in its entirety on October 11, 2005, subject to the provisions of paragraphs 4 and 6 hereof. Except as provided in paragraph 6 hereof, the Option may not be exercised unless the Optionee shall, at the time of exercise, be an employee of the Corporation or one of its Affiliates. The Optionee shall not have any of the rights of a shareholder with respect to any of the Common Shares subject to the Option until such shares shall be issued to the Optionee upon due exercise of the Option.

     4. Change of Control. Notwithstanding the provisions of paragraph 3 hereof, from and after a Change of Control (as hereinafter defined) the Option shall become immediately exercisable in full. As used herein, “Change of Control” shall mean any of the following events:

     (a) The acquisition by any person, entity or “group,” within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), other than the Corporation or any of its Affiliates, or any employee benefit plan of the Corporation and/or one or more of its Affiliates, of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 15% or more of either the then outstanding Common Shares or the combined voting power of the Corporation’s then outstanding voting securities in a transaction or series of transactions not approved in advance by a vote of at least three-quarters of the Continuing Directors (as hereinafter defined); or

     (b) Individuals who, as of the Grant Date, constitute the Board of Directors of the Corporation (generally the “Directors” and as of the Grant Date the “Continuing Directors”) cease for any reason to constitute at least a majority thereof, provided that any person becoming a Director subsequent to the Grant Date whose nomination for election was approved in advance by a vote of at least three-quarters of the Continuing Directors (other than a nomination of an individual whose initial assumption of office is in connection with an actual or threatened solicitation with respect to the election or removal of the Directors of the Corporation, as such terms are used in Rule 14a-11 of Regulation 14A under the Exchange Act) shall be deemed to be a Continuing Director; or

     (c) The approval by the shareholders of the Corporation of a reorganization, merger, consolidation, liquidation or dissolution of the Corporation or of the sale (in one transaction or a series of related transactions) of all or substantially all of the assets of the Corporation other than a reorganization, merger, consolidation, liquidation, dissolution or sale approved in advance by a vote of at least three-quarters of the Continuing Directors;

     (d) The first purchase under any tender offer or exchange offer (other than an offer by the Corporation or any of its Affiliates) pursuant to which Common Shares are purchased; or

     (e) At least a majority of the Continuing Directors determines in their sole discretion that there has been a change in control of the Corporation.

     5. Transferability. The Option shall not be transferable other than by will or the laws of descent and distribution, and the Option may be exercised during the lifetime of the Optionee only by the Optionee. More particularly (but without limiting the generality of the foregoing), the Option may not be assigned, transferred (except as aforesaid), pledged or hypothecated in any way (whether by operation of law or otherwise) and shall not be subject to execution, attachment or similar process. Any attempted assignment, transfer, pledge, hypothecation, or other disposition of the Option contrary to the provisions hereof and the levy of an execution, attachment or similar process upon the Option shall be void. Notwithstanding the foregoing,

2

Optionee may, in the manner established by the Committee, designate a beneficiary or beneficiaries to exercise the rights of the Optionee with respect to the Option upon the death of the Optionee.

     6. Effect of Termination of Employment.

          (a) In the event the Optionee shall cease to be employed by the Corporation or any of its Affiliates for any reason other than termination for cause, death, disability, termination within two years following a Change in Control, or retirement after reaching age 55, the Optionee may exercise the Option at any time within three months after such termination of employment, but not thereafter; provided, however, that the Option may not be exercised after the Expiration Date and may be exercised only to the extent of the number of shares the Optionee was entitled to purchase under the Option on the date of such termination.

          (b) In the event the Optionee shall cease to be employed by the Corporation or any of its Affiliates upon termination for cause, the Option shall be terminated as of the date of such termination. Termination for cause shall mean termination of Optionee’s employment with the Corporation or any of its Affiliates for the following acts: dishonesty, fraud, conviction or confession of a felony or of a crime involving moral turpitude, destruction or theft of the property of the Corporation or any of its Affiliates, willful malfeasance or gross negligence, misconduct materially injurious to the Corporation or any of its Affiliates, participation in fraud against the Corporation or any of its Affiliates, entering into competition against the Corporation or any of its Affiliates, and/or a material breach or threatened material breach of any other agreements with the Corporation or any of its Affiliates.

          (c) In the event the Optionee shall cease to be employed by the Corporation or any of its Affiliates within two years following a Change in Control, the Optionee may exercise the Option at any time after such termination of employment, provided, however, that the Option may not be exercised after the Expiration Date.

          (d) In the event the Optionee terminates employment due to retirement from the Corporation or any of its Affiliates after reaching age 55, the Option shall remain in full force and effect, and continue to vest in accordance with paragraph 3 hereof.

          (e) In the event that the Optionee shall cease to be employed by the Corporation or any of its Affiliates as the result of death or disability, or the Optionee shall die within three months after the termination of the Optionee’s employment other than for cause, the Option may be exercised by the Optionee or, if applicable, by the Optionee’s personal representative or administrator or by any person or persons to whom the Option is transferred by will or the applicable laws of descent and distribution, at any time within a period of one year after the termination of employment of the Optionee, but not after the Expiration Date, to the full extent of the Common Shares covered by the Option not previously purchased, whether or not such shares had become purchasable by the Optionee at the date of the Optionee’s termination of employment. For purposes of this Agreement, an Optionee shall be deemed to have a disability if such Optionee is deemed to be disabled under any long-term disability program then

3

maintained by the Corporation or any of its Affiliates that is applicable to the Optionee; provided, however, that if no such long-term plan is then maintained, the determination of disability shall be in the exclusive and sole discretion of the Corporation.

     (f) The Option shall not be affected by any change of the duties or position of the Optionee (or by a temporary leave of absence approved by the Corporation) so long as the Optionee continues to be an employee of the Corporation or of an Affiliate.

     (g) Nothing herein contained shall confer on the Optionee any right to continue in the employ of the Corporation or any Affiliate or affect in any way the right of the Corporation or any Affiliate to terminate the employment of the Optionee at any time.

     7. Anti-dilution Adjustments. If any portion of the Option is exercised subsequent to any stock dividend, split-up, recapitalization, merger, consolidation, combination or exchange of shares or the like occurring after the Grant Date as a result of which shares of any class shall be issued in respect of the outstanding Common Shares, or Common Shares shall be changed into the same or a different number of shares of the same or another class or classes, the person or persons exercising the Option shall receive for the aggregate price paid upon such exercise the aggregate number of shares which, if Common Shares (as authorized at the Grant Date) had been purchased at the Grant Date for the same aggregate price (on the basis of the price per share set forth in paragraph 2 hereof) and had not been disposed of, such person or persons would be holding at the time of such exercise as a result of such purchase and any and all such stock dividends, split-ups, recapitalizations, mergers, consolidations, combinations or exchanges of shares, or the like; provided, however, that no fractional share shall be issued upon any such exercise, and the aggregate price paid shall be appropriately reduced on account of any fractional share not issued.

     8. Manner of Exercise. The Option may be exercised by written notice to Wells Fargo Investment, LLC as prescribed by the Corporation. The notice shall state the number of shares with respect to which the Option is being exercised. The notice shall be accompanied by payment of the full purchase price and the Corporation or its agent shall issue and deliver a certificate representing such shares as soon as practicable after the notice is received. Payment of the purchase price shall, unless otherwise consented to by the Corporation, be made by delivery of cash, check (bank check, certified check or personal check) or money order payable to the order of the Corporation Certificates for the shares purchased shall be registered in the name of the person exercising the Option (or if the Option shall be exercised by the Optionee and if the Optionee shall so request in the notice exercising the Option, shall be registered in the name of the Optionee and another person as joint tenants) and shall be delivered to the person exercising the Option. In the event the Option shall be exercised pursuant to paragraph 6(d) hereof by any person other than the Optionee, the notice shall be accompanied by appropriate proof of such person’s right to exercise the Option. All shares issued upon the exercise of the Option shall be fully paid and non-assessable.

     9. Taxes. The Optionee acknowledges that the Optionee will consult with the Optionee’s personal tax advisor regarding the income tax consequences of exercising the Option

4

or any other matters related to this Agreement. In order to provide the Corporation with the opportunity to claim the benefit of any income tax deduction which may be available to it upon exercise of the Option, and in order to comply with all applicable income tax laws or regulations, the Corporation may take such action as it deems appropriate to insure that, if necessary, all applicable federal or state payroll, withholding, income or other taxes are withheld or collected from the Optionee. In accordance with the terms of the Plan, and such rules as may be adopted by the Committee under the Plan, the Optionee may elect to satisfy the Optionee’s federal and state income tax withholding obligations upon exercise of the Option by (a) delivering cash, check (bank check, certified check or personal check) or money order payable to the order of the Corporation, or (b) having the Corporation withhold a portion of the Common Shares otherwise to be delivered upon exercise of the Option having a Fair Market Value equal to the amount of federal and state income tax required to be withheld upon such exercise, in accordance with such rules as the Corporation may from time to time establish.

     10. Miscellaneous.

          (a) The Corporation shall reserve and keep available such number of Common Shares as will be sufficient to satisfy the requirements of this Agreement.

          (b) If any of the shares covered by this Agreement are not registered under the Securities Act of 1933 at the time of their issuance hereunder, the Optionee represents and agrees that all such shares purchased under the Option will be acquired for investment and not for resale.

          (c) As used in this Agreement, the term “Common Shares” shall mean the Common Shares of the Corporation as authorized at the Grant Date, and the terms “Affiliate,” “Committee” and “Fair Market Value” shall have the meanings ascribed to them in the Plan.

          (d) This Option is granted pursuant to the Plan and is subject to all the terms and conditions contained therein. A copy of the Plan is available to the Optionee upon request.

          (e) This Agreement shall be governed by and construed in accordance with the laws of the State of Minnesota.

          (f) Headings in this Agreement are for convenience of reference only and shall not be deemed in any way to be material or relevant to the construction or interpretation of this Agreement or any provision hereof.

          (g) THIS 2005 NONQUALIFIED STOCK OPTION AGREEMENT IS ATTACHED TO AND MADE A PART OF A STOCK OPTION AWARD CERTIFICATE AND SHALL HAVE NO FORCE OR EFFECT UNLESS SUCH STOCK OPTION AWARD CERTIFICATE IS DULY EXECUTED AND DELIVERED BY THE CORPORATION AND THE OPTIONEE.

* * * * * * * *

5

OTTER TAIL CORPORATION
1999 STOCK INCENTIVE PLAN
STOCK OPTION AWARD CERTIFICATE

[Name and address of Optionee]

[Social Security Number of Optionee]

     You have been granted options to purchase shares of Otter Tail Corporation Common Stock as follows:

Grant Type:	Nonqualified Stock Option
Grant Date:	April 11, 2005
Stock Option Plan:	1999 Stock Incentive Plan
Option Price Per Share:	$
Total Number of Shares Granted:
Expiration Date:	April 11, 2015

     By the Corporation’s and your signature below, it is agreed that these options are granted under and governed by the terms and conditions of the 2005 Nonqualified Stock Option Agreement, a copy of which is attached and made a part of this document, and the Corporation’s 1999 Stock Incentive Plan, a copy of which is enclosed.

OTTER TAIL CORPORATION

OTTER TAIL CORPORATION
By:
	John Erickson
	Its: President & Chief Executive Officer
	[Name of Optionee]

6

EX-10.N.8 3 c02868exv10wnw8.htm FORM OF RESTRICTED STOCK AGREEMENT

Exhibit 10-N-8

OTTER TAIL CORPORATION
1999 STOCK INCENTIVE PLAN
2005 RESTRICTED STOCK AWARD AGREEMENT
FOR EMPLOYEES

     This Restricted Stock Award Agreement for Employees is between Otter Tail Corporation, a Minnesota corporation (the “Corporation”), and the person named in the attached Restricted Stock Award Certificate for Employees who is an employee of the Corporation or one of its Affiliates (the “Participant”), effective as of the date of grant (the “Grant Date”) set forth in the attached Restricted Stock Award Certificate for Employees.

     WHEREAS, the Corporation, pursuant to the Otter Tail Corporation 1999 Stock Incentive Plan (the “Plan”), wishes to award to the Participant a number of the Corporation’s Common Shares, par value $5.00 per share (the “Common Shares”), subject to certain restrictions and on the terms and conditions contained in this Agreement and in the attached Restricted Stock Award Certificate for Employees, which is made a part hereof.

     NOW, THEREFORE, for good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the Corporation and the Participant hereby agree as follows:

     1. Award of Restricted Stock. The Corporation hereby grants to the Participant, effective as of the Grant Date, an award of restricted stock for that number of Common Shares set forth in the attached Restricted Stock Award Certificate for Employees (the “Shares”), on the terms and conditions set forth in this Agreement, the Restricted Stock Award Certificate for Employees and the 1999 Stock Incentive Plan.

     2. Rights of the Participant with Respect to the Shares. With respect to the Shares, the Participant shall be entitled at all times on and after the date of issuance of the Shares to exercise the rights of a shareholder of Common Shares of the Corporation, including the right to vote the Shares and the right to receive dividends thereon as provided in Section 8 hereof, unless and until the Shares are forfeited pursuant to Section 5(b) hereof. The rights of the Participant with respect to the Shares shall remain forfeitable at all times prior to the date or dates on which such rights become vested, and the restrictions with respect to the Shares lapse, in accordance with Section 3, 4 or 5(a) hereof.

     3. Vesting. Subject to the terms and conditions of this Agreement, the Shares shall vest, and the restrictions with respect to the Shares shall lapse, in installments on the dates and in the amounts set forth in the attached Restricted Stock Award Certificate for Employees if the Participant remains continuously employed by the Corporation or an Affiliate of the Corporation until the respective vesting dates.

     4. Change of Control. Notwithstanding the vesting provision contained in Section 3 above, but subject to the other terms and conditions set forth herein, upon the occurrence of a

Change of Control (as defined below) prior to any termination of the Participant’s employment, the Participant shall become immediately and unconditionally vested in all of the Shares, and the restrictions with respect to all of the Shares shall lapse. As used herein, “Change of Control” shall mean any of the following events:

     (a) The acquisition by any person, entity or “group,” within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), other than the Corporation or any of its Affiliates, or any employee benefit plan of the Corporation and/or one or more of its Affiliates, of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 15% or more of either the then outstanding Common Shares or the combined voting power of the Corporation’s then outstanding voting securities in a transaction or series of transactions not approved in advance by a vote of at least three-quarters of the Continuing Directors (as hereinafter defined); or

     (b) Individuals who, as of the Grant Date, constitute the Board of Directors of the Corporation (generally the “Directors” and as of the Grant Date the “Continuing Directors”) cease for any reason to constitute at least a majority thereof, provided that any person becoming a Director subsequent to the Grant Date whose nomination for election was approved in advance by a vote of at least three-quarters of the Continuing Directors (other than a nomination of an individual whose initial assumption of office is in connection with an actual or threatened solicitation with respect to the election or removal of the Directors of the Corporation, as such terms are used in Rule 14a-11 of Regulation 14A under the Exchange Act) shall be deemed to be a Continuing Director; or

     (c) The approval by the shareholders of the Corporation of a reorganization, merger, consolidation, liquidation or dissolution of the Corporation or of the sale (in one transaction or a series of related transactions) of all or substantially all of the assets of the Corporation other than a reorganization, merger, consolidation, liquidation, dissolution or sale approved in advance by a vote of at least three-quarters of the Continuing Directors;

     (d) The first purchase under any tender offer or exchange offer (other than an offer by the Corporation or any of its Affiliates) pursuant to which Common Shares are purchased; or

     (e) At least a majority of the Continuing Directors determines in their sole discretion that there has been a change in control of the Corporation.

     5. Additional Vesting Rules; Forfeiture.

          (a) If the Participant ceases to be employed by the Corporation or any of its Affiliates by reason of disability (as determined under any long-term disability program then maintained by the Corporation or any of its Affiliates that is applicable to the Participant), retirement (normal or early retirement under any retirement plan of the Corporation or any of its Affiliates that is applicable to the Participant) or death prior to the vesting of the Shares pursuant to Section 3 or 4 hereof, the shares shall continue to vest, and the restrictions with respect to the

2

shares shall lapse in installments on the dates and in the amounts set forth in the Restricted Stock Award Certificate for Employees for the benefit of the Participant or the Participant’s legal representatives, beneficiaries, or heirs as the case may be. No transfer by will or the applicable laws of descent and distribution of any Shares which vest by reason of the Participant’s death shall be effective to bind the Corporation unless the Committee shall have been furnished with written notice of such transfer and a copy of the will or such other evidence as the Committee may deem necessary to establish the validity of the transfer.

          (b) If the Participant elects to terminate the employment relationship with the Corporation or any of its Affiliates (unless for Good Reason as described in (c) below) or is terminated for cause, the Participant’s rights to all of the unvested Shares shall be immediately and irrevocably forfeited, including the right to vote such Shares and the right to receive cash dividends. Unless otherwise defined in an Employment Agreement dated on or before the Grant Date, cause shall mean continued failure to substantially perform the Participant’s duties or misconduct that is materially injurious to the Corporation.

          (c) If the Participant is terminated by the Corporation or any of its Affiliates without cause, or if the Participant elects to terminate employment with the Corporation or any of its Affiliates for Good Reason (as defined in an Employment Agreement dated on or before the Grant Date) the shares shall continue to vest, and the restrictions with respect to the shares shall lapse in installments on the dates and in the amounts set forth in the Restricted Stock Award Certificate for Employees.

     6. Restriction on Transfer. Until the Shares vest pursuant to Section 3, 4 or 5(a) hereof, none of the Shares may be sold, assigned, transferred, pledged, hypothecated or otherwise disposed of or encumbered, and no attempt to transfer the Shares, whether voluntary or involuntary, by operation of law or otherwise, shall vest the transferee with any interest or right in or with respect to the Shares.

     7. Issuance and Custody of Certificates.

          (a) The Corporation shall cause to be issued one or more stock certificates, registered in the Participant’s name, representing the Shares. Each such certificate shall be subject to an appropriate stop-transfer order and shall bear the following legend:

“The Common Shares represented by this certificate are subject to forfeiture, and the transferability of this certificate and the Common Shares represented hereby are subject to the restrictions, terms and conditions (including restrictions against transfer) contained in the Otter Tail Corporation 1999 Stock Incentive Plan and a Restricted Stock Award Agreement between Otter Tail Corporation and the registered owner of such shares. Release from such restrictions, terms and conditions shall be made only in accordance with the provisions of the Plan and the Agreement, copies of which are on file in the office of the Secretary of Otter Tail Corporation.”

3

          (b) Upon execution of this Agreement, the Participant shall execute and deliver to the Corporation a stock power or stock powers relating to the Shares.

          (c) Each certificate issued pursuant to Section 7(a) hereof, together with the stock power or stock powers relating to the Shares, shall be deposited by the Corporation with the Secretary of the Corporation or a custodian designated by the Secretary.

          (d) After any Shares vest pursuant to Section 3, 4 or 5(a) hereof, and following payment of the applicable withholding taxes pursuant to Section 9 hereof, the Corporation shall promptly cause to be issued a certificate or certificates, registered in the Participant’s name or in the name of the Participant’s legal representatives, beneficiaries or heirs, as the case may be, representing such vested Shares (less any shares withheld to pay withholding taxes), free of the legend provided in Section 7(a) hereof and any stop-transfer order with respect to such Shares, and shall cause such certificate or certificates to be delivered to the Participant or the Participant’s legal representatives, beneficiaries or heirs, as the case may be.

     8. Distributions and Adjustments.

          (a) If any Shares vest in the Participant subsequent to any change in the number or character of the Common Shares of the Corporation (through recapitalization, stock split, stock dividend, reorganization, merger, consolidation or otherwise), the Participant shall then receive upon such vesting the number and type of securities or other consideration which the Participant would have received if such Shares had vested prior to the event changing the number or character of the outstanding Common Shares.

          (b) Any additional Common Shares of the Corporation, any other securities of the Corporation and any other property (except for cash dividends or other cash distributions) distributed with respect to the Shares prior to the date or dates the Shares vest shall be subject to the same restrictions, terms and conditions as the Shares to which they relate and shall be promptly deposited with the Secretary of the Corporation or a custodian designated by the Secretary.

          (c) Any cash dividends or other cash distributions payable with respect to the Shares shall be distributed to the Participant at the same time cash dividends or other cash distributions are distributed to shareholders of the Corporation generally.

     9. Income Tax Matters.

          (a) The Participant acknowledges that the Participant will consult with the Participant’s personal tax advisor regarding the income tax consequences of the grant of the Shares, payment of dividends on the Shares and the vesting of the Shares or any other matters related to this Agreement. In order to comply with all applicable federal or state income tax laws or regulations, the Corporation may take such action as it deems appropriate to ensure that all applicable federal or state payroll, withholding, income or other taxes, which are the sole and absolute responsibility of the Participant, are withheld or collected from the Participant.

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          (b) In accordance with the terms of the Plan, and such rules as may be adopted by the Committee under the Plan, the Participant may elect to satisfy the Participant’s federal and state income tax withholding obligations arising from the receipt of, or the lapse of restrictions relating to, the Shares by (i) delivering cash, check (bank check, certified check or personal check) or money order payable to the order of the Corporation, or (ii) having the Corporation withhold a portion of the Shares otherwise to be delivered having a Fair Market Value equal to the amount of such taxes. The Corporation will not deliver any fractional Share but will pay, in lieu thereof, the Fair Market Value of such fractional Share. The Participant’s election must be made on or before the date that the amount of tax to be withheld is determined.

     10. Miscellaneous.

          (a) Nothing contained in this Agreement or the Plan shall confer on the Participant any right to continue in the employ of the Corporation or any Affiliate or affect in any way the right of the Corporation or any Affiliate to terminate the employment of the Participant at any time.

          (b) The Corporation shall not be required to deliver any Shares until the requirements of any federal or state securities laws, rules or regulations or other laws or rules (including the rules of any securities exchange) as may be determined by the Corporation to be applicable are satisfied.

          (c) This Agreement is subject to the terms of the Plan. Terms used in this Agreement which are not defined herein shall have the respective meanings given to such terms in the Plan. A copy of the Plan is available to the Participant upon request.

          (d) This Agreement shall be governed by and construed in accordance with the internal laws of the State of Minnesota, without giving effect to the conflicts of laws principles thereof.

          (e) Headings in this Agreement are for convenience of reference only and shall not be deemed in any way to be material or relevant to the construction or interpretation of this Agreement or any provision hereof.

          (f) THIS RESTRICTED STOCK AWARD AGREEMENT FOR EMPLOYEES IS ATTACHED TO AND MADE A PART OF A RESTRICTED STOCK AWARD CERTIFICATE FOR EMPLOYEES AND SHALL HAVE NO FORCE OR EFFECT UNLESS SUCH RESTRICTED STOCK AWARD CERTIFICATE FOR EMPLOYEES IS DULY EXECUTED AND DELIVERED BY THE CORPORATION AND THE PARTICIPANT.

* * * * * * * *

5

OTTER TAIL CORPORATION
1999 STOCK INCENTIVE PLAN

RESTRICTED STOCK AWARD CERTIFICATE FOR EMPLOYEES

     This certifies the award of restricted stock as specified below which has been granted under the Otter Tail Corporation 1999 Stock Incentive Plan (the “Plan”), the terms and conditions of which are incorporated by reference herein and made a part hereof. In addition, the award shown in this Certificate is nontransferable and is subject to the terms and conditions set forth in the attached 2005 Restricted Stock Award Agreement for Employees of which this Certificate is a part.

[Name and address of recipient]

[Social Security Number of recipient]

You have been granted the following Award:

Grant Type:	Restricted Stock
Number of Common Shares:
Grant Date:	April 11, 2005
Vesting Schedule:

	Percentage of
Date	Restricted Stock Vested
April 8, 2006		25	%
April 8, 2007		25	%
April 8, 2008		25	%
April 8, 2009		25	%

     By the Corporation’s and your signature below, it is agreed that this award of restricted stock is governed by the terms and conditions of the 2005 Restricted Stock Award Agreement for Employees, a copy of which is attached and made a part of this document, and the Corporation’s 1999 Stock Incentive Plan, a copy of which is enclosed.

OTTER TAIL CORPORATION
By:
	John D. Erickson
	President and Chief Executive Officer
	[Name of recipient]

6

EX-13.A 4 c02868exv13wa.htm PORTIONS OF 2005 ANNUAL REPORT TO SHAREHOLDERS

Exhibit 13-A

Selected Consolidated Financial Data

(thousands, except number of shareholders and per-share data)	2005			2004			2003			2002			2001			2000			1995
Revenues
Electric	$	312,985		$	266,385		$	267,494		$	244,005		$	232,720		$	219,718		$	192,053
Plastics		158,548			115,426			86,009			82,931			63,216			82,667			4,569
Manufacturing (1)		244,311			201,615			157,401			119,880			96,571			73,940			34,121
Health services		123,991			114,318			100,912			93,420			79,129			66,319			50,896
Food Ingredient Processing		38,501			14,023			—			—			—			—			—
Other business operations (1)		171,939			148,328			114,726			75,947			72,191			70,145			28,984
Intersegment eliminations		(3,867	)		(2,733	)		(2,254	)		(1,036	)		—			—			—
Total operating revenues	$	1,046,408		$	857,362		$	724,288		$	615,147		$	543,827		$	512,789		$	310,623
Income from continuing operations (1)		52,855			40,632			38,225			44,222			40,055			37,654			28,305
Income from discontinued operations (1)		9,696			1,563			1,431			1,906			3,548			3,388			640
Net income		62,551			42,195			39,656			46,128			43,603			41,042			28,945
Operating cash flow from continuing operations (1)		90,358			54,330			76,314			71,582			71,025			57,110			56,404
Operating cash flow — continuing and discontinued operations		95,800			56,301			76,955			76,797			77,529			61,761			58,077
Capital expenditures — continuing operations (1)		59,969			49,484			48,783			73,447			50,727			44,655			36,343
Total assets		1,181,496			1,134,148			986,423			914,112			817,778			772,562			643,173
Long-term debt (1)		258,260			261,805			262,311			254,015			221,643			188,031			160,235
Redeemable preferred		—			—			—			—			—			18,000			18,000
Basic earnings per share — continuing operations (1) (2)		1.79			1.53			1.46			1.73			1.55			1.46			1.16
Basic earnings per share — total (2)		2.12			1.59			1.52			1.80			1.69			1.59			1.19
Diluted earnings per share — continuing operations (1) (2)		1.78			1.52			1.45			1.71			1.53			1.45			1.16
Diluted earnings per share — total (2)		2.11			1.58			1.51			1.79			1.68			1.59			1.19
Return on average common equity		13.9	%		12.0	%		12.2	%		15.3	%		15.5	%		15.4	%		14.8	%
Dividends per common share		1.12			1.10			1.08			1.06			1.04			1.02			0.88
Dividend payout ratio		53	%		70	%		72	%		59	%		62	%		64	%		74	%
Common shares outstanding — year end		29,401			28,977			25,724			25,592			24,653			24,574			22,360
Number of common shareholders (3)		14,801			14,889			14,723			14,503			14,358			14,103			13,933

Notes:
(1)	Prior years are restated to exclude the operations of Midwest Information Systems, Inc., St George Steel Fabrication, Inc. and Chassis Liner Corporation, which are classified as discontinued operations. See note 15 to consolidated financial statements.
(2)	Based on average number of shares outstanding.
(3)	Holders of record at year end.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

Otter Tail Corporation and our subsidiaries form a diverse group of businesses with operations classified into six segments: electric, plastics, manufacturing, health services, food ingredient processing and other business operations. Our primary financial goals are to maximize earnings and cash flows and to allocate capital profitably toward growth opportunities that will increase shareholder value. Meeting these objectives enables us to preserve and enhance our financial capability by maintaining desired capitalization ratios and a strong interest coverage position, and preserving solid credit ratings on outstanding securities, which, in the form of lower interest rates, benefits both our customers and shareholders.

Our vision is to create value and growth through ownership and acquisition of well-run companies in diverse businesses. Our strategy is straightforward: Reliable utility performance combined with growth opportunities at all our businesses provides long-term value. This includes growing our core electric utility business which provides a strong base of revenues, earnings and cash flows. In addition, we look to our 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. We adhere to strict guidelines when reviewing acquisition candidates since our 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, we also avoid concentrating business risk within a single industry. All our operating companies operate under a decentralized business model with disciplined corporate oversight.

We assess the performance of our operating companies over time, using the following criteria:

• ability to provide returns on invested capital that exceed our weighted average cost of capital over the long term; and

• assessment of an operating company’s business and potential for future earnings growth.

We are a committed long-term owner and therefore we do not acquire companies in pursuit of short-term gains. However, we will divest operating companies if they do not meet these criteria over the long term.

The following major events occurred in our company in 2005:

• Our annual consolidated revenues topped $1 billion for the first time in our history.

• We reported record consolidated earnings and record earnings in our electric and plastics segments.

• We sold three of our operating companies for a net after-tax gain of $10.0 million.

• In June we jointly announced an agreement with six other regional utilities to build a new 600-megawatt coal-fired electric generating plant (BSP II) on the site of the existing Big Stone Plant if all necessary permits and approvals are granted on a timely basis.

Major growth strategies and initiatives in our company’s future include:

• Planned capital budget expenditures of $477 million for the years 2006-2010, including $247 million related to BSP II, if built.

• The continued investigation and evaluation of strategic acquisition opportunities.

• Pursuing the regulatory approvals, financing and other arrangements necessary to build BSP II.

The following table summarizes our consolidated results of operations for the years ended December 31:

(in thousands)	2005		2004
Operating revenues:
Electric	$	312,985	$	266,385
Nonelectric		733,423		590,977
Total operating revenues	$	1,046,408	$	857,362
Net income from continuing operations:
Electric	$	37,301	$	31,535
Nonelectric		15,554		9,097
		52,855		40,632
Net income from discontinued operations		9,696		1,563
Total net income	$	62,551	$	42,195

The 22.0% increase in consolidated revenues in 2005 compared with 2004 reflects revenue growth in all our business segments. Revenues in the electric segment increased $46.6 million reflecting a $24.6 million increase in retail electric revenue, a $19.2 million increase in wholesale energy and mark-to-market revenues and a $2.8 million increase in other electric revenue. Revenues grew $43.1 million in our plastics segment in 2005 primarily as a result of rising resin prices and increased demand for polyvinyl chloride (PVC) pipe, particularly following the 2005 Gulf Coast hurricanes. Revenues increased $42.7 million in our manufacturing segment in 2005 as a result of increased unit sales and price increases related to increases in raw material costs, sales of higher priced products and the acquisitions of three companies in 2005. Revenues from our health services segment increased $9.7 million. Scanning and other related service revenues increased $13.9 million while revenues from equipment sales and service decreased $4.2 million between the years. Revenues in our food ingredient processing segment were $38.5 million for 2005 compared with $14.0 million from our 19 weeks of ownership in 2004. Other business operations revenue grew by $23.6 million with most of the increase coming from our energy services company as a result of higher natural gas prices in 2005.

A 93% increase in net margins from wholesale electric sales and energy trading activities and a 3.2% increase in retail electric megawatt-hour sales were the main contributing factors to the $5.8 million increase in electric segment net income. A record year in our plastics segment and an increase in earnings from continued improvements in our health services segment were the major factors contributing to the $6.5 million increase in net income from our nonelectric business segments in 2005 compared with 2004.

Following is a more detailed analysis of our operating results by business segment for the three years ended December 31, 2005, 2004 and 2003, followed by our outlook for 2006, a discussion of our financial position at the end of 2005 and risk factors that may affect our future operating results and financial position.

RESULTS OF OPERATIONS

This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes found elsewhere in this report. See note 2 to our consolidated financial statements for a complete description of our lines of business, locations of operations and principal products and services.

Amounts presented in the segment tables that follow for 2005, 2004 and 2003 operating revenues, cost of goods sold and other nonelectric operating expenses will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

(in thousands)	2005		2004		2003
Operating revenues	$	3,867	$	2,733	$	2,254
Cost of goods sold		2,070		1,083		527
Other nonelectric expenses		1,797		1,650		1,727

ELECTRIC

The following table summarizes the results of operations for our electric segment for the years ended December 31:

			%				%
(in thousands)	2005		change		2004		change		2003
Retail sales revenues	$	248,939		11	$	224,326		3	$	217,439
Wholesale revenues		41,953		75		24,000		(6)		25,644
Net marked-to-market gains		4,444		38		3,228		(20)		4,058
Other revenues		17,649		19		14,831		(27)		20,353
Total operating revenues	$	312,985		17	$	266,385		—	$	267,494
Production fuel		55,927		7		52,056		2		51,163
Purchased power – system use		58,828		47		40,098		11		36,002
Other operation and maintenance expenses		99,904		17		85,361		(2)		87,186
Depreciation and amortization		24,397		1		24,236		(7)		26,008
Property taxes		10,043		(4)		10,411		8		9,598
Operating income	$	63,886		18	$	54,223		(6)	$	57,537

The $24.6 million increase in retail revenues from 2004 to 2005 includes $16.0 million in increased fuel clause adjustment (FCA) revenues directly related to increases in fuel and purchased power costs in 2005 and $8.6 million from a 3.2% increase in retail kilowatt-hour (kwh) sales. Residential kwh sales increased 3.9% primarily due to an 86% increase in cooling degree-days in the summer of 2005 compared with the summer of 2004. Kwh sales to commercial and industrial customers increased 3.0% due to an improving regional economy.

Wholesale revenues increased $18.0 million in 2005 compared with 2004. 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 (FTRs). Virtual transactions are of two types: 1) A Virtual Demand Bid is a bid to purchase energy in MISO’s Day-Ahead Market that is not backed by physical load. 2) A Virtual Supply Offer 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. We recorded $12.7 million in net revenues related to virtual transactions in 2005. 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 FTRs can be granted 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. We recorded $1.9 million in net revenue related to bilateral trading of FTRs in MISO’s secondary market in 2005. In 2005, net revenues from the purchase and sale of electric energy contracts, including virtual transactions and FTRs, increased $11.2 million, compared with net revenues from energy trading activities in 2004, on a 178% increase in kwh volume traded between the years. As the MISO markets evolve and become more efficient, profits from virtual and FTR transactions may be reduced. Revenues from wholesale energy sales from company-owned generation increased $6.8 million due to a 58.9% increase in the average price per kwh sold in 2005 compared with 2004, offset by a 13.2% reduction in kwh sales. The increase in the average price per kwh is reflective of a general increase in energy prices in 2005 related to increased fuel costs.

The $1.2 million increase in net mark-to-market gains on forward energy contracts is due to an increase in the volume of forward energy contracts entered into in 2005 compared to 2004 combined with increasing energy prices in 2005. At December 31, 2005 the electric utility had recorded $2.9 million in net gains on forward energy contracts to be settled in 2006 compared with $0.3 million in recorded net gains on forward energy contracts at December 31, 2004 that were settled in 2005.

The $2.8 million increase in other electric revenues is related mostly to transmission studies completed by Otter Tail Power Company for MISO and transmission line permitting work done for other companies.

In December 2005, the Minnesota Public Utilities Commission (MPUC) issued an order denying the recovery of certain MISO-related costs through the 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 electric utility to reflect the refund obligation. On February 9, 2006 the MPUC reconsidered its December 2005 order. On reconsideration, the MPUC 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 possible recovery through base rates in the electric utility’s next general rate case. The MPUC’s final written order of this action is pending. When the final order is issued, the electric utility will recognize the $1.9 million in revenue and reverse the refund payable.

The $3.9 million increase in production fuel costs in 2005 compared with 2004 reflects a 15.5% increase in the cost of fuel per kwh generated, partially offset by a 7.0% reduction in generation. The decrease in kwhs generated is mainly due to the seven-week maintenance shutdown of Big Stone Plant in 2005. Fuel costs per kwh of generation increased at all three of our coal-fired generating plants as a result of increases in mine operating costs and, in the case of Hoot Lake and Big Stone Plants, increased costs for transporting coal by rail. Much of the increase in mine operating and coal transportation costs is directly related to a sharp increase in diesel fuel prices in 2005. Also, the overall increase in production fuel costs is partially attributable to our generation mix in 2005. Kwh generation at our higher-cost Hoot Lake generating units increased 25% in 2005 compared with 2004 while kwh generation at our lower-cost Big Stone and Coyote generating units decreased 21% and 6%, respectively, between the years. Fuel costs at our combustion turbine peaking plants increased $2.5 million (110%) while kwh generation increased by only 7.6%, reflecting increases in natural gas and fuel oil prices in 2005 and decreased plant efficiencies resulting from MISO dispatch directives.

Purchased power costs to serve retail customers increased $18.7 million as a result of a 28.2% increase in kwh purchases combined with a 14.5% increase in the cost per kwh purchased. Kwh purchases increased to make up for the shortfall caused by the Big Stone Plant shutdown and to provide for increased demand among retail electric customers. The increase in the cost per kwh of purchased power in 2005 is partially due to increases in fuel costs and partially due to a decrease in available electricity from hydro-generation in the region due to lower

water levels in Upper Missouri River reservoirs resulting from a prolonged drought in the Upper Missouri River basin. Approximately 90% of fuel and purchased power cost increases associated with service to retail electric customers is subject to recovery through the fuel cost recovery component of retail rates.

The $14.5 million increase in other operation and maintenance expenses in 2005 compared with 2004 includes increases of: $7.4 million in labor and benefits expense, $1.8 million in costs related to contract work performed for others, $1.5 million in storm damage repair costs, $1.3 million in tree-trimming and transmission line and pole maintenance expenditures and $1.1 million in maintenance expenses related to the seven-week maintenance shutdown of Big Stone Plant in 2005. The increase in labor and benefit expenses is due to wage and salary increases averaging 3.6%, and increases in pension costs, storm-related overtime pay, performance bonuses and safety awards.

The $0.4 million decrease in property taxes in 2005 compared with 2004 is a result of slightly lower utility property valuations in Minnesota in 2005.

The $6.9 million increase in retail revenues from 2003 to 2004 is mainly due to a $4.0 million increase in FCA revenues. The remaining increase in retail revenues was due to a 1.5% increase in retail kwh sales. The increase in retail sales reflects a 3.2% increase in kwh sales to commercial and industrial customers, partially offset by a 2.0% decrease in kwh sales to residential customers. The increase in commercial and industrial kwh sales reflects increased sales to pipeline customers related to increased oil prices and increased sales to large commercial customers due to a rebounding economy in 2004. Residential kwh sales decreased mainly as a result of a 55.7% decrease in cooling degree-days in the summer of 2004 compared with the summer of 2003. The increase in FCA revenues is due to a 16.3% increase in kwh purchases for retail use in 2004 compared with 2003. Fuel and purchased power costs for retail use also increased as a result of higher retail kwh demand in 2004 compared with 2003.

Wholesale revenues from sales of company-owned generation decreased $0.6 million in 2004 compared with 2003 due to a 1.9% decrease in kwh sales combined with a 1.5% decrease in revenue per kwh of generation sold. Fuel costs per kwh of generation used for wholesale sales decreased 2.6% between the years resulting in a decrease in the gross margin per kwh sold from company-owned generation of only 0.2%. Net margins on purchased power resold decreased $1.0 million despite a 2.2% increase in kwh sales as a result of a 16.3% decrease in the gross margin per kwh of purchased power resold. The 2003 mid-year change in the revenue recognition methodology (applied to resales of purchased power from contract-based prices to market-based prices as a result of adopting SFAS No. 133 in July 2003) is a contributing factor to the 16.3% decrease in the gross margin per kwh of purchased power resold between 2003 and 2004. The $0.8 million decrease in net mark-to-market gains on forward energy contracts reflects the recognition of $2.1 million in net gains related to the initial adoption of mark-to-market accounting on forward energy contracts in July 2003, partially offset by a $1.3 million increase in mark-to-market gains recognized in 2004 compared with 2003 as a result of applying mark-to-market accounting to forward energy contracts for all of 2004 compared with applying it for only six months of 2003.

In 2003, other electric operating revenues included revenues from contracted construction work completed on a large wind farm project in North Dakota. The electric utility did not have a construction contract of similar magnitude in 2004, which is the main reason for the $5.5 million reduction in other electric revenues between 2003 and 2004.

The $1.8 million decrease in other operation and maintenance expenses in 2004 compared with 2003 includes a $3.2 million reduction in costs related to contracted construction work on the wind farm project completed in 2003. This reduction was partially offset by increases in regulatory expenses and increases in expenses related to transmission services, and a $0.6 million net increase in labor and benefit expenses after taking into account a $0.7 million reduction in retiree medical benefit costs related to the Medicare prescription drug benefit subsidy recorded in 2004.

The $1.8 million decrease in depreciation and amortization expense for 2004 compared with 2003 is related to the extension of the depreciable service lives of certain units of electric utility property. The extension of these depreciable service lives was included in the electric utility’s annual depreciation study and depreciation rates approved by the MPUC. The $0.8 million increase in property taxes in 2004 compared with 2003 is mainly related to a 9.0% increase in the value of electric utility property apportioned to Minnesota related to the value the State of Minnesota assigned to the utility’s Solway combustion turbine generator property.

PLASTICS

The following table summarizes the results of operations for our plastics segment for the years ended December 31:

			%				%
(in thousands)	2005		change		2004		change		2003
Operating revenues	$	158,548		37	$	115,426		34	$	86,009
Cost of goods sold		121,245		25		97,126		28		76,046
Operating expenses		10,939		91		5,718		50		3,824
Depreciation and amortization		2,511		9		2,297		8		2,126
Operating income	$	23,853		132	$	10,285		156	$	4,013

The $43.1 million increase in plastics operating revenues in 2005 compared with 2004 reflects a 31.9% increase in the average sales price per pound of PVC pipe sold combined with a 3.2% increase in pounds of PVC pipe sold between the years. The increase in revenue reflects the effect of rising resin prices and increased customer demand for PVC pipe. Demand accelerated to record levels late in the third quarter of 2005 as substantial resin price increases were announced and concerns developed over the adequacy of resin supply following the 2005 Gulf Coast hurricanes. A majority of U.S. resin production plants are located in the Gulf Coast region. The increase in revenues was partially offset by a $24.1 million increase in cost of goods sold, reflecting a 19.9% increase in the average cost per pound of pipe sold. The average cost per pound of resin, the raw material used to produce PVC pipe, increased 16.4% between the periods. The $5.2 million increase in operating expenses between the periods primarily is due to increases in costs directly related to increased sales. The increase in depreciation and amortization expense relates mostly to manufacturing equipment purchased in 2004 and 2005.

The $29.4 million increase in plastics operating revenues in 2004 compared with 2003 reflects a 10.8% increase in the pounds of PVC pipe sold between the years combined with an 18.2% increase in the average sales price per pound of pipe sold. The increase in revenues was partially offset by a $21.1 million increase in cost of goods sold reflecting an 11.7% increase in the average cost per pound of pipe sold. The average cost per pound of resin increased 19.0% between the periods. The $1.9 million increase in operating expenses between the periods primarily is due to increases in costs directly related to increased sales along with increases in building rental expenses and property taxes related to our polyethylene pipe plant in Hampton, Iowa, which began operations in summer 2003. The increase in depreciation and amortization expense relates mostly to manufacturing equipment purchased in 2003 and 2004.

MANUFACTURING

Operating results for the manufacturing segment for 2004 and 2003 have changed as a result of the reclassification of St. George Steel Fabrication, Inc. and Chassis Liner Corporation to discontinued operations in 2005. The following table summarizes the results of operations for our manufacturing segment for the years ended December 31:

			%				%
(in thousands)	2005		change		2004		change		2003
Operating revenues	$	244,311		21	$	201,615		28	$	157,401
Cost of goods sold		194,264		23		157,802		29		122,763
Operating expenses		23,872		13		21,098		14		18,471
Depreciation and amortization		9,447		21		7,828		14		6,882
Operating income	$	16,728		12	$	14,887		60	$	9,285

Revenue increases at the manufacturing companies in 2005 compared with 2004 are due to a combination of factors including increased unit sales, increased sales of higher-priced products, higher prices related to material cost increases and 2005 acquisitions. The increase in cost of goods sold in the manufacturing segment was proportional to the increase in sales revenue resulting in a $6.2 million increase in manufacturing segment gross profits between the periods.

The increase in revenues in our manufacturing segment in 2005 compared with 2004 relates to the following:

• Revenues at DMI Industries, Inc. (DMI), our manufacturer of wind towers, increased $23.8 million (48.9%) due to increased production and sales activity. This is in part related to the production tax credits for wind-generated electricity being in place for 2005 as well as improvements in productivity and capacity utilization.

• Revenues at BTD Manufacturing Inc. (BTD), our metal parts stamping and fabrication company, increased $10.2 million (14.9%) mainly as a result of product price increases to cover rising material costs reflected in an 11.8% increase in revenue per unit sold between the periods. The purchase of Performance Tool in January 2005 contributed $3.8 million toward BTD’s revenue increase.

• Revenues at ShoreMaster, Inc., our waterfront equipment manufacturer, increased $4.9 million (9.5%) due to the acquisitions of Shoreline Industries and Southeast Floating Docks, offset in part by a decline in revenues in its residential and commercial divisions.

• Revenues at T.O. Plastics, Inc., our manufacturer of thermoformed plastic and horticultural products, increased $3.8 million (11.6%) as a result of productivity improvements and higher prices that provided for recovery of increased raw material costs.

The increase in cost of goods sold in our manufacturing segment in 2005 compared with 2004 relates to the following:

• DMI cost of goods sold increased $18.4 million between the periods as a result of increased production and higher raw material costs, subcontractor and labor costs. DMI cost of goods sold also includes a $1.0 million write-down of inventory in the third quarter 2005 for tower sections that have limited use in the wind business due to changes in wind tower design requirements.

• Cost of goods sold at BTD increased $12.1 million as a result of higher raw material and labor costs mainly related to increased production. The purchase of Performance Tool in January 2005 contributed $2.8 million toward BTD’s increase in cost of goods sold.

• ShoreMaster’s $3.8 million increase in cost of goods sold is mainly related to the acquisitions of Shoreline Industries and Southeast Floating Docks and increases in material costs.

• T.O. Plastics cost of goods sold increased $2.3 million between the periods as a result of increased material costs.

The increase in operating expenses in our manufacturing segment in 2005 compared with 2004 relates to the following:

• DMI operating expenses increased $1.2 million as a result of a $0.5 million increase in wages, salaries and benefit expenses, a $0.4 million increase in costs associated with changes in plant layout to improve productivity and a $0.2 million increase in repairs and maintenance costs.

• ShoreMaster’s operating expenses increased $1.5 million mainly as a result of the acquisitions of Shoreline Industries and Southeast Floating Docks in January and May of 2005.

Depreciation expense increased in 2005 compared with 2004 as a result of 2004 equipment additions and the 2005 manufacturing segment acquisitions.

The manufacturing segment’s improved performance in 2004 compared with 2003 can be attributed to certain companies within this segment being able to offset increases in commodity prices with product pricing increases and increased productivity and capacity utilization. The increases in productivity at BTD and DMI resulted in a combined increase in manufacturing segment operating income from these two companies of $6.5 million in 2004 compared with 2003. Revenue increases at the other manufacturing companies were offset by increased costs and operating expenses resulting in a combined net decrease in operating income from these companies of $0.9 million in 2004 compared with 2003.

The increase in revenues in our manufacturing segment in 2004 compared with 2003 relates to the following:

• Revenues at BTD increased $18.5 million (36.8%) as a result of product price increases related to increases in raw material costs, especially steel, and a 12.7% increase in the number of units produced and sold at BTD’s expanded manufacturing facilities in 2004 compared with 2003.

• DMI revenues increased $11.3 million (30.4%) reflecting product price increases related to increased steel prices and increased productivity and plant utilization in 2004.

• ShoreMaster revenues increased $8.6 million (19.7%) as a result of increases in sales of residential waterfront equipment, increases in jobs in progress and product price increases related to higher raw material costs.

• Revenues at T.O. Plastics increased $5.8 million (21.8%) as a result of a 14.2% increase in units sold in 2004 compared with 2003.

The $35.0 million increase in cost of goods sold in 2004 compared with 2003 includes increases of $13.3 million at BTD, $8.8 million at ShoreMaster, $7.7 million at DMI and $5.2 million at T.O. Plastics as a result of production increases and higher raw material costs at each of the companies.

The $2.6 million net increase in manufacturing segment operating expenses in 2004 compared with 2003 includes $1.9 million in increased expenses at BTD (reflecting increases in compensation and promotional expenses related to increased sales and losses related to the disposal of equipment no longer used in production) and $0.9 million in increased sales commissions at ShoreMaster. The $0.9 million increase in depreciation and amortization expense in 2004 compared with 2003 is mainly due to 2004 and 2003 equipment purchases at three of our manufacturing companies.

HEALTH SERVICES

The following table summarizes the results of operations for our health services segment for the years ended December 31:

			%				%
(in thousands)	2005		change		2004		change		2003
Operating revenues	$	123,991		8	$	114,318		13	$	100,912
Cost of goods sold		90,327		5		85,731		14		75,117
Operating expenses		21,989		25		17,593		14		15,410
Depreciation and amortization		4,038		(20)		5,047		(2)		5,137
Operating income	$	7,637		28	$	5,947		13	$	5,248

The $9.7 million increase in health services operating revenues for 2005 compared with 2004 reflects an increase of $13.9 million in scanning and other related service revenues offset by a decline in revenues from equipment sales and service of $4.2 million between the periods. The revenue per scan and the number of scans completed increased 9.6% and 5.9%, respectively. The imaging business added to its fleet of medical imaging equipment in 2005 resulting in an increase in revenue from rentals and interim installations of scanning equipment and related technical support services. The increase in health services revenue was partially offset by increases in cost of goods sold and operating expenses of $9.0 million to support the increases in imaging services activity. The increase in cost of goods sold is mainly related to increased equipment rental costs and increased labor costs partially offset by decreases in materials and maintenance costs. The increase in operating expenses is mainly due to increased payroll and travel expenses and increases in contractual allowances and bad debt expense between the periods and losses on equipment sales in 2005. The decrease in depreciation and amortization expense is the result of certain assets reaching the ends of their depreciable lives. When these assets are replaced, they are generally replaced with assets leased under operating leases. Improved operating efficiencies in the imaging business and service cost reductions initiated in 2004 along with growing scan counts have contributed to improved results in the health services segment.

The $13.4 million increase in health services operating revenues for 2004 compared with 2003 reflects $6.9 million in additional imaging revenues and $6.5 million from sales and servicing of equipment. The number of scans performed on a fee-per-scan basis decreased 14.1% while the average fee per scan increased 17.7%. The increase in revenue from equipment sales includes $1.8 million in increased revenue related to the acquisitions of Topline Medical and North Star Medical Systems in May and July of 2003. The $10.6 million increase in cost of goods sold in 2004 compared with 2003 includes $4.5 million related to equipment sales and $6.1 million related to imaging and other services. The $2.2 million increase in operating expenses reflects increases in compensation and benefits expenses and increases in travel expenses related to the 2003 medical equipment company acquisitions and an expansion of imaging services.

FOOD INGREDIENT PROCESSING

The following table summarizes the results of operations for our food ingredient processing segment for the periods ended December 31:

	2005		2004
(in thousands)	(full year)		(19 weeks)
Operating revenues	$	38,501	$	14,023
Cost of goods sold		30,930		11,379
Operating expenses		2,533		876
Depreciation and amortization		3,399		1,118
Operating income	$	1,639	$	650

The increases in revenues, cost of goods sold, operating expenses and depreciation and amortization are due to 2004 results reflecting only 19 weeks of operating activity as a result of the acquisition of Idaho Pacific Holdings, Inc. (IPH) in August 2004. Disclosure of pro forma information related to the results of operations of IPH for the periods presented in this report is not required due to immateriality.

Consistent with trends in the industry, operating income for 2005 was less than expected as a result of lower sales volume and prices, high energy costs, increasing raw material costs and the increasing value of the Canadian dollar relative to the U.S. dollar.

OTHER BUSINESS OPERATIONS

The following table summarizes the results of operations for our other business operations segment for the years ended December 31:

				%					%
(in thousands)	2005			change		2004			change		2003
Operating revenues	$	171,939			16	$	148,328			29	$	114,726
Cost of goods sold		131,951			17		113,054			37		82,378
Operating expenses		52,468			22		42,907			17		36,646
Goodwill impairment loss		1,003			—		—			—		—
Depreciation and amortization		2,666			(9)		2,945			4		2,841
Operating (loss)	$	(16,149	)		(53)	$	(10,578	)		(48)	$	(7,139	)

The increases in operating revenues and cost of goods sold in our other business operations in 2005 compared with 2004 are due to the following:

• Revenues at OTESCO, our energy services company, increased $20.4 million (45.8%), which includes $20.9 million in increased revenue from natural gas sales mainly as a result of increases in natural gas prices between the periods. The increase in revenue from natural gas sales was almost entirely offset by a $20.6 million increase in natural gas costs between the years. OTESCO also recorded a net increase in technical services revenue of $0.2 million between the years and a net loss on natural gas forward swap transactions of $0.5 million in 2005 compared to a net gain of $0.2 million recorded in 2004.

• Revenues at Midwest Construction Services, Inc. (MCS), our electrical design and construction services company, increased $16.6 million (61.4%) between the years as a result of an increase in work in progress, which was mostly offset by a $13.7 million increase in cost of goods sold including $4.4 million in increased material and labor costs incurred on a single project that resulted in a significant loss on that project.

• Revenues at E.W. Wylie Corporation (Wylie), our flatbed trucking company, increased $3.7 million (13.7%) in 2005 compared with 2004 due to a 9.7% increase in miles driven by company-operated and owner-operated trucks and a $0.9 million increase in fuel surcharge revenue.

• Revenues at Foley Company, a mechanical and prime contractor on industrial projects, decreased $17.2 million (35.4%) in 2005 compared with 2004 due to a decrease in jobs in progress. The decrease in Foley’s revenues was mostly offset by a decrease of $15.4 million in material, subcontractor, labor and insurance costs between the periods.

The increase in operating expenses in our other business operations segment in 2005 compared with 2004 relates to the following:

• Wylie’s operating expenses increased $3.9 million as a result of higher fuel prices, increased fuel usage and labor costs related to the increase in miles driven and increases in truck leasing costs between the periods.

• Increases in employee health insurance and other employee benefit costs and increases in insurance costs at our captive insurance company contributed $1.9 million to the increase in net losses in this segment.

• MCS reported increased expenses of $0.8 million for wages and benefits, outside contracted services and advertising and promotions in 2005 compared with 2004.

The $1.0 million goodwill impairment loss in 2005 relates to the write-off of goodwill at OTESCO in the third quarter of 2005 as a result of a reassessment of its future cash flows in light of rising natural gas prices and greater market volatility in future prices for natural gas.

Wylie’s depreciation and amortization expenses decreased by $0.3 million between the periods as a result of a 2004 decision to lease rather than buy replacement trucks for their fleet.

The increases in operating revenues and cost of goods sold in our other business operations in 2004 compared with 2003 are due to the following:

• Revenues at Foley Company, acquired in November 2003, increased $40.6 million and Foley’s cost of goods sold increased $36.7 million between the years, reflecting a full year of operations in 2004.

• Revenues at OTESCO increased $8.6 million (23.9%) and its cost of goods sold increased $8.5 million between the years mainly due to increases in natural gas prices.

• Wylie’s revenues increased $1.9 million (7.8%) reflecting increased brokerage activity and the pass through of increased diesel fuel prices to customers. Brokered miles increased 5.5% between the years while the combined miles driven by company-owned trucks and owner-operated trucks decreased 7.4%.

• MCS revenues decreased $17.7 million (39.5%) and cost of goods sold decreased $14.6 million between the periods due to a lower volume of available work in combination with excess capacity in MCS’s construction market.

The increase in operating expenses in our other business operations segment in 2004 compared with 2003 relates to the following:

• Foley’s operating expenses were $3.2 million for 2004 compared with $0.5 million for two months of operations in 2003.

• Wylie’s operating expenses increased $1.9 million mainly as a result of higher fuel prices and increased brokerage activity between the periods.

• Operating expenses in 2004 reflect $1.3 million in increased unallocated corporate overhead costs mainly due to increases in employee benefit costs and increased expenses for professional services related to compliance with Sarbanes-Oxley Section 404 requirements.

• MCS reported increased expenses of $0.7 million, mostly due to increases in payroll and advertising and promotional expenses in 2004 compared with 2003.

• OTESCO’s general and administrative expenses decreased $0.3 million between the years.

CONSOLIDATED INTEREST CHARGES

Interest expense increased $0.4 million in 2005 compared to 2004 primarily as a result of increased interest rates on short-term debt. In 2005, short-term debt interest expense was $1.6 million at an average rate of 3.7% on an average daily balance of $42.6 million, compared with $1.2 million at an average rate of 2.2% on an average daily balance of $57.8 million in 2004.

Interest expense increased $0.5 million in 2004 compared to 2003 primarily as a result of interest expense on the bridge loan used to finance the acquisition of IPH.

CONSOLIDATED INCOME TAXES

The 60% increase in income tax expense from continuing operations in 2005 compared to 2004 is due, in part, to a 39% increase in income from continuing operations before income taxes. Our effective tax rate on income from continuing operations was 34.6% for 2005 compared with 30.0% for 2004. The difference in the effective tax rate for 2005 compared to 2004 is a function of the level of fixed deductions and credits in proportion to higher net income before tax in 2005 compared to 2004. See note 14 to consolidated financial statements.

Our effective tax rate on income from continuing operations was 30.0% for 2004 compared with 27.0% for 2003. Approximately 1.0% of the difference in the effective tax rate for 2004 compared to 2003 reflects the impact of R&D tax credits claimed in 2003. The remaining 2.0% difference in the effective tax rate for 2004 compared to 2003 is a function of the level of fixed deductions and credits in proportion to higher net income before tax in 2004 compared to 2003.

DISCONTINUED OPERATIONS

Discontinued operations includes the operating results of Midwest Information Systems (MIS), a telecommunications company located in Parkers Prairie, Minnesota, St. George Steel Fabrication, Inc. (SGS), a structural steel fabricator located in St. George, Utah, and Chassis Liner Corporation (CLC) a manufacturer of auto and truck frame-straightening equipment and accessories located in Alexandria, Minnesota. The sales of MIS and SGS were completed in the second quarter of 2005. The sale of CLC was completed in the fourth

quarter of 2005. The following table presents operating revenues, expenses, including interest and other income and deductions, and income taxes, included on a net basis in income from discontinued operations on our 2005, 2004 and 2003 consolidated statements of income.

				%				%
(in thousands)	2005			change		2004		change		2003
Operating revenues	$	16,449			(51)	$	33,701		16	$	28,951
Expenses		16,978			(45)		31,098		16		26,752
Income tax (benefit) expense		(221	)		—		1,040		35		768
(Loss) income from discontinued operations	$	(308	)		—	$	1,563		9	$	1,431

The following table presents the pre-tax and net-of-tax gains and losses recorded on the sales of the three companies in 2005.

(in thousands)	MIS			SGS			CLC			Total
Gain (loss) on sale	$	19,025		$	(2,919	)	$	(271	)	$	15,835
Income tax (expense) benefit		(7,107	)		1,168			108			(5,831	)
Net gain (loss) on sale	$	11,918		$	(1,751	)	$	(163	)	$	10,004

IMPACT OF INFLATION

The electric utility operates under regulatory provisions that allow price changes in fuel and certain purchased power costs to be passed to most retail customers through automatic adjustments to its rate schedules under fuel clause adjustments. Other increases in the cost of electric service must be recovered through timely filings for electric rate increases with the appropriate regulatory agency.

Our plastics, manufacturing, health services, food ingredient processing, and other business operations consist entirely of unregulated businesses. Increased operating costs are reflected in product or services pricing with any limitations on price increases determined by the marketplace. Raw material costs, labor costs and interest rates are important components of costs for companies in these segments. Any or all of these components could be impacted by inflation or other pricing pressures, with a possible adverse effect on our profitability, especially where increases in these costs exceed price increases on finished products. In recent years, our operating companies have faced strong inflationary and other pricing pressures with respect to steel, fuel, resin, lumber, concrete, aluminum and health care costs, which have been partially mitigated by pricing adjustments.

2006 EXPECTATIONS

We anticipate 2006 diluted earnings per share from continuing operations will be in a range from $1.60 to $1.80. Contributing to the earnings expectations for 2006 are the following items:

• We expect solid performance in the electric segment in 2006 although net income is anticipated to be lower than 2005 levels. This is primarily because margins on wholesale electric sales are expected to be tighter as the MISO market becomes more efficient, anticipated increases in transmission service and wage and benefit costs, and uncertainty related to the recoverability of certain MISO-related costs through the fuel clause adjustments in Minnesota and North Dakota retail rates. We expect earnings for the electric segment in 2006 to return to more historical levels.

• We expect the plastics segment performance to return to more historical levels in 2006 following the 2005 record year.

• The improving economy, continued enhancements in productivity and capacity utilization, expanded markets, expansion of production capacity with the opening of a new wind tower production facility in Fort Erie, Ontario, Canada, and continued availability of production tax credits are expected to result in increased net income in our manufacturing segment.

• Our health services segment is expected to have moderate growth in net income in 2006.

• We expect our food ingredient processing business to generate net income in the range of $2 million to $4 million for the year ending December 31, 2006.

• Our other business operations segment is expected to show improved results over 2005 due to an improving economy and an increase in its backlog of construction contracts. An increase in wind energy projects activity is expected to have a positive impact on our electrical contracting business.

• We anticipate investing approximately $57 million in capital expenditures during 2006 in addition to funding possible future acquisitions.

• Our outlook for 2006 reflects the impact of Statement of Financial Accounting Standards No. 123(R), Share-Based Payment, which is anticipated to lower diluted earnings per share results by $0.015 per share in 2006. This standard requires all share-based compensation awards be measured at fair value at the date of grant and expensed over their vesting or service periods. This standard is effective beginning in January 2006.

Our outlook for 2006 is dependent on a variety of factors and is subject to the risks and uncertainties discussed under “Risk Factors and Cautionary Statements.”

LIQUIDITY

We believe our financial condition is strong and that our cash, other liquid assets, operating cash flows, access to capital markets through our universal shelf registration and borrowing ability because of solid credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. However, our operating cash flow and access to capital markets can be impacted by macroeconomic factors outside our control. In addition, our borrowing costs can be impacted by short-term and long-term debt ratings assigned to us by independent rating agencies, which in part are based on certain credit measures such as interest coverage and leverage ratios.

We have achieved a high degree of long-term liquidity by maintaining desired capitalization ratios and solid credit ratings, implementing cost-containment programs and investing in projects that provide returns in excess of our weighted average cost of capital.

Cash provided by operating activities from continuing and discontinued operations was $95.8 million in 2005 compared with $56.3 million in 2004. The $39.5 million increase in cash from operations reflects a $13.3 million increase in net income (net of the $3.0 million increase in noncash depreciation and amortization expense and excluding the $10.0 million gain on the sale of discontinued operations) and a $34.3 million increase in payables

and other current liabilities offset by a $7.8 million increase in receivables, inventories and other current assets between the years. The increase in payables and other current liabilities includes: $11.5 million related to PVC resin purchased in the fourth quarter of 2005 under extended payment terms related to a normal slowdown in business in the fourth quarter, $6.5 million in incentive compensation accrual increases related to improved results in the electric and plastics business segments in 2005 and increased production activity at DMI, $5.4 million in billings in excess of costs at DMI and Shoremaster related to an increase in jobs in progress at year-end 2005 compared with year-end 2004, a $4.7 million increase in accounts payable at DMI related to a large steel shipment received in December 2005, a $1.9 million refund payable related to a MPUC order in December 2005, and an increase of $3.4 million in deposits, deferred revenues and business insurance reserves at year-end 2005 compared to year-end 2004. The increase in receivables and inventories reflects increases in receivables, mainly at MCS and the plastic pipe companies and increases in inventories primarily at the manufacturing companies. While consolidated accounts receivables are higher at December 31, 2005 compared with December 31, 2004, the average days outstanding for accounts receivable decreased between the years.

The $91.1 million decrease in net cash used in investing activities in 2005 compared with 2004 reflects a $57.8 million decrease in cash used to complete acquisitions and $34.2 million in proceeds from the sales of MIS, SGS and CLC in 2005. The decrease in cash used for acquisitions and other investments is mostly related to the 2004 acquisition of IPH, in which $68.2 million in cash was paid and $6.0 million was placed in escrow to pay off earn-out contingencies if IPH achieved certain financial targets for the period from August 1, 2004 through July 31, 2005. The financial targets were not achieved and the $6.0 million in escrow was returned to the Company in August 2005, contributing to cash flows from other investments in 2005. A breakdown of capital expenditures by segment is provided below under Capital Requirements.

Cash paid for acquisitions in 2005 net of cash acquired included the following:

Company	(thousands)
Performance Tool	$	4,116
Shoreline Industries		2,328
Southeast Floating Docks		3,968
Contingency payments—prior years’ acquisitions		811
Total	$	11,223

Net cash used in financing activities was $62.0 million in 2005 compared with net cash provided by financing activities of $55.9 million in 2004. Major uses of cash for financing activities in 2005 were:

• $32.7 million for the payment of dividends on common shares outstanding

• $24.0 million for repayment of short-term debt

• $7.2 million for the retirement of long-term debt

The $9.7 million in net proceeds from the issuance of common stock in 2005 included $5.8 million from the exercise of stock options and $4.3 million from the issuance of 175,000 common shares in January 2005 as a result of the underwriters exercising a portion of their over-allotment option in connection with our December 2004 public offering.

CAPITAL REQUIREMENTS

We have a capital expenditure program for the expansion, upgrade and improvement of our plants and operating equipment. Typical uses of cash for capital expenditures are investments in electric generation facilities, transmission and distribution lines, equipment used in the manufacturing process, purchase of diagnostic medical equipment, transportation equipment and computer hardware and information systems. The capital expenditure program is subject to review and is revised annually in light of changes in demands for energy, technology, environmental laws, regulatory changes, business expansion opportunities, the costs of labor, materials and equipment and our consolidated financial condition.

Consolidated capital expenditures for the years 2005, 2004 and 2003 were $60.0 million, $49.5 million and $48.8 million, respectively. The estimated capital expenditures for 2006 are $57.4 million and the total capital expenditures for the five-year period 2006 through 2010 are estimated to be approximately $477 million, which includes $247 million for our share of expected expenditures for construction of the planned BSP II electric generating plant and related transmission assets if all necessary permits and approvals are granted on a timely basis.

The breakdown of 2003, 2004 and 2005 actual and 2006 through 2010 estimated capital expenditures by segment is as follows:

(in millions)	2003		2004		2005		2006		2006-2010
Electric	$	28	$	25	$	30	$	29	$	381
Plastics		4		3		4		8		18
Manufacturing		10		13		16		13		55
Health services		6		4		3		1		3
Food ingredient processing		—		4		3		4		15
Other business operations		1		1		4		2		5
Total	$	49	$	50	$	60	$	57	$	477

The following table summarizes our contractual obligations at December 31, 2005 and the effect these obligations are expected to have on our liquidity and cash flow in future periods.

			Less than		1-3		3-5		More than
(in millions)	Total		1 year		years		years		5 years
Long-term debt obligations	$	262	$	3	$	58	$	5	$	196
Interest on long-term debt obligations		141		16		27		24		74
Operating lease obligations		136		37		59		37		3
Capacity and energy requirements		110		17		33		24		36
Coal contracts (required minimums)		84		16		22		12		34
Postretirement benefit obligations		47		4		7		8		28
Other purchase obligations		42		42		—		—		—
Total contractual cash obligations	$	822	$	135	$	206	$	110	$	371

Interest on $22.0 million of variable-rate debt outstanding on December 31, 2005 was projected based on the interest rates applicable to those debt instruments on December 31, 2005.

CAPITAL RESOURCES

Financial flexibility is provided by operating cash flows, our universal shelf registration, unused lines of credit, strong financial coverages, solid credit ratings, and alternative financing arrangements such as leasing. We have the ability to issue up to $256 million of common stock, preferred stock, debt and certain other securities from time to time under our universal shelf registration statement filed with the Securities and Exchange Commission. Additional equity or debt financing may be required in the period 2006 through 2010 in the event we decide to refund or retire early any of our presently outstanding debt or cumulative preferred shares, to retire the $50 million 6.375% senior debentures due December 1, 2007, to complete acquisitions, to fund the construction of the new BSP II generating station at the Big Stone Plant site or for other corporate purposes. There can be no assurance that any additional required financing will be available through bank borrowings, debt or equity financing or otherwise, or that if such financing is available, it will be available on terms acceptable to us. If adequate funds are not available on acceptable terms, our businesses, results of operations and financial condition could be adversely affected.

Our $100 million line of credit with U.S. Bank National Association, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, and Bank Hapoalim B.M., expires on April 26, 2006. The terms of the current line of credit are essentially the same as those in place in the prior agreement. However, outstanding letters of credit issued by the company can reduce the amount available for borrowing under the line by up to $20 million. Borrowings under the line of credit bear interest at LIBOR plus 0.6%, subject to adjustment based on the ratings of our senior unsecured debt. We do not anticipate any difficulties in renewing this line of credit.

Our bank line of credit is a key source of operating capital and can provide interim financing of working capital and other capital requirements, if needed. This line is an unsecured revolving credit facility available to support borrowings of our nonelectric operations. We anticipate that the electric utility’s cash requirements will be provided for by cash flows from electric utility operations. Our obligations under this line of credit are guaranteed by our 100%-owned subsidiary that owns substantially all of our nonelectric companies. As of December 31, 2005, $16.0 million of the $100 million line of credit was in use and $12.0 million was restricted from use to cover outstanding letters of credit.

Our line of credit, $90 million 6.63% senior notes and Lombard US Equipment Finance note contain the following covenants: a debt-to-total capitalization ratio not in excess of 60% and an interest and dividend coverage ratio of at least 1.5 to 1. The 6.63% senior notes also require that priority debt not be in excess of 20% of total capitalization. We were in compliance with all of the covenants under our financing agreements as of December 31, 2005.

Our obligations under the 6.63% senior notes are guaranteed by our 100%-owned subsidiary that owns substantially all of our nonelectric companies. Our Grant County and Mercer County pollution control refunding revenue bonds require that we grant to Ambac Assurance Corporation, under a financial guaranty insurance policy relating to the bonds, a security interest in the assets of the electric utility if the rating on our senior unsecured debt is downgraded to Baa2 or below (Moody’s) or BBB or below (Standard & Poor’s).

On August 26, 2005 Moody’s Investor Service lowered its ratings of our senior unsecured debt from A2 to A3 and our preferred stock from Baa1 to Baa2 and changed its outlook from negative to stable. On December 22, 2005 Standard & Poor’s Rating Services affirmed our corporate credit rating and senior unsecured debt rating of BBB+. At the same time the outlook was revised from negative to stable.

Our securities ratings at December 31, 2005 are:

	Moody’s
	Investors		Standard
	Service		& Poor’s
Senior unsecured debt		A3	BBB+
Preferred stock	Baa2		BBB–
Outlook	Stable		Stable

Disclosure of these securities ratings is not a recommendation to buy, sell or hold our securities. Downgrades in these securities ratings could adversely affect our company. Further downgrades could increase borrowing costs resulting in possible reductions to net income in future periods and increase the risk of default on our debt obligations.

Our ratio of earnings to fixed charges from continuing operations, which includes imputed finance costs on operating leases, was 4.3x for 2005 compared to 3.4x for 2004 and our long-term debt interest coverage ratio before taxes was 6.3x for 2005 compared to 4.9x for 2004. During 2006, we expect these coverage ratios to decrease from 2005 levels assuming 2006 net income meets our expectations.

OFF-BALANCE-SHEET ARRANGEMENTS

We do not have any off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.

RISK FACTORS AND CAUTIONARY STATEMENTS

We are including the following factors and cautionary statements in this Annual Report to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by us or on our behalf. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are other than statements of

historical facts. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All these forward-looking statements, whether written or oral and whether made by us or on our behalf, are also expressly qualified by these factors and cautionary statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of the factors, nor can we assess the effect of each factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The following factors and the other matters discussed herein are important factors that could cause actual results or outcomes for our company to differ materially from those discussed in the forward-looking statements included elsewhere in this document.

GENERAL

Our plans to grow and diversify through capital expenditures and acquisitions may not be successful, which could result in poor financial performance.

As part of our business strategy, we intend to acquire new businesses. We may not be able to identify appropriate acquisition candidates or successfully negotiate, finance or integrate acquisitions. If we are unable to make acquisitions, we may be unable to realize the growth we anticipate. Future acquisitions could involve numerous risks including: difficulties in integrating the operations, services, products and personnel of the acquired business; and the potential loss of key employees, customers and suppliers of the acquired business. If we are unable to successfully manage these risks of an acquisition, we could face reductions in net income in future periods.

Federal and state environmental regulation could require us to incur substantial capital expenditures which could result in increased operating costs.

We are subject to federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources and health safety. These laws and regulations regulate the modification and operation of existing facilities, the construction and operation of new facilities and the proper storage, handling, cleanup and disposal of hazardous waste and toxic substances. Compliance with these legal requirements requires us to commit significant resources and funds toward environmental monitoring, installation and operation of pollution control equipment, payment of emission fees and securing environmental permits. Obtaining environmental permits can entail significant expense and cause substantial construction delays. Failure to comply with environmental laws and regulations, even if caused by factors beyond our control, may result in civil or criminal liabilities, penalties and fines.

Existing environmental laws or regulations may be revised and new laws or regulations may be adopted or become applicable to us. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material effect on our results of operations.

Volatile financial markets could restrict our ability to access capital and increase our borrowing costs and pension plan expenses.

We rely on access to both short- and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations. If we are not able to access capital at competitive rates, the ability to implement our business plans may be adversely affected. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or adversely affect our ability to access one or more financial markets.

Changes in the U.S. capital markets could also have significant effects on our pension plan. Our pension income or expense is affected by factors including the market performance of the assets in the master pension trust maintained for the pension plans for some of our employees, the weighted average asset allocation and long-term rate of return of our pension plan assets, the discount rate used to determine the service and interest cost components of our net periodic pension cost and assumed rates of increase in our employees’ future compensation. If our pension plan assets do not achieve positive rates of return, or if our estimates and assumed rates are not accurate, our company’s earnings may decrease because net periodic pension costs would rise and we could be required to provide additional funds to cover our obligations to employees under the pension plan.

ELECTRIC

We may experience fluctuations in revenues and expenses related to our electric operations, which may cause our financial results to fluctuate and could impair our ability to make distributions to shareholders or scheduled payments on our debt obligations.

A number of factors, many of which are beyond our control, may contribute to fluctuations in our revenues and expenses from electric operations, causing our net income to fluctuate from period to period. These risks include fluctuations in the volume and price of sales of electricity to customers or other utilities, which may be affected by factors such as mergers and acquisitions of other utilities, geographic location of other utilities, transmission costs (including increased costs related to operations of regional transmission organizations), changes in the manner in which wholesale power is sold and purchased, unplanned interruptions at our generating plants, the effects of regulation and legislation, demographic changes in our customer base and changes in our customer demand or load growth. Electric wholesale margins could be reduced as the MISO market becomes more efficient. Electric wholesale trading margins could be reduced or eliminated by losses due to trading activities. Other risks include weather conditions (including severe weather that could result in damage to our assets), fuel and purchased power costs and the rate of economic growth or decline in our service areas. A decrease in revenues or an increase in expenses related to our electric operations may reduce the amount of funds available for our existing and future businesses, which could result in increased financing requirements, impair our ability to make expected distributions to shareholders or impair our ability to make scheduled payments on our debt obligations. As of December 31, 2005 we had capitalized $1.8 million in costs related to the planned construction of a second electric generating unit at our Big Stone Plant site. If approvals of permits are not received on a timely basis, the project could be at risk. If the project is abandoned, any costs capitalized prior to abandonment would be subject to expense.

Actions by the regulators of our electric operations could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures.

The corporation is subject to government regulations and regulatory actions that may have a negative impact on its business and results of operations. The electric rates that we are allowed to charge for our electric services are one of the most important items influencing our financial position, results of operations and liquidity. The rates

that we charge our electric customers are subject to review and determination by state public utility commissions in Minnesota, North Dakota and South Dakota. We are also regulated by the Federal Energy Regulatory Commission. An adverse decision by one or more regulatory commissions concerning the level or method of determining electric utility rates, the authorized returns on equity, implementation of enforceable federal reliability standards or other regulatory matters, permitted business activities (such as ownership or operation of nonelectric businesses) or any prolonged delay in rendering a decision in a rate or other proceeding (including with respect to the recovery of capital expenditures in rates) could result in lower revenues and net income.

We may not be able to respond effectively to deregulation initiatives in the electric industry, which could result in reduced revenues and earnings.

We may not be able to respond in a timely or effective manner to the changes in the electric industry that may occur as a result of regulatory initiatives to increase wholesale competition. These regulatory initiatives may include further deregulation of the electric utility industry in wholesale markets. Although we do not expect retail competition to come to the states of Minnesota, North Dakota and South Dakota in the foreseeable future, we expect competitive forces in the electric supply segment of the electric business to continue to increase, which could reduce our revenues and earnings.

Our electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

Operation of electric generating facilities involves risks which can adversely affect energy output and efficiency levels. Most of our generating capacity is coal-fired. We rely on a limited number of suppliers of coal, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railroad for shipments of coal to our Big Stone and Hoot Lake Plants, making us vulnerable to increased prices for coal transportation from a sole supplier. Higher fuel prices result in higher electric rates for our retail customers through fuel clause adjustments and could make us less competitive in wholesale electric markets. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, intentional acts of destruction or other similar occurrences affecting the electric generating facilities. The loss of a major generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.

PLASTICS

Our plastics operations are highly dependent on a limited number of vendors for PVC resin and a limited supply of PVC resin. The loss of a key vendor, or any interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for our plastics business.

We rely on a limited number of vendors to supply the PVC resin used in our plastics business. Two vendors accounted for approximately 97% of our total purchases of PVC resin in 2005 and approximately 98% of our total purchases of PVC resin in 2004. In addition, the supply of PVC resin may be limited primarily due to manufacturing capacity and the limited availability of raw material components. The loss of a key vendor or any interruption or delay in the availability or supply of PVC resin could disrupt our ability to deliver our plastic products, cause customers to cancel orders or require us to incur additional expenses to obtain PVC resin from alternative sources, if such sources are available.

We compete against a large number of other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish our products from those of our competitors.

The plastic pipe industry is highly fragmented and competitive, due to the large number of producers and the fungible nature of the product. We compete not only against other PVC pipe manufacturers, but also against ductile iron steel, concrete and clay pipe manufacturers. Due to shipping costs, competition is usually regional, instead of national, in scope, and the principal areas of competition are a combination of price, service, warranty and product performance. Our inability to compete effectively in each of these areas and to distinguish our plastic pipe products from competing products may adversely affect the financial performance of our plastics business.

MANUFACTURING

Competition from foreign and domestic manufacturers, the price and availability of raw materials, the availability of production tax credits and general economic conditions could affect the revenues and earnings of our manufacturing businesses.

Our manufacturing businesses are subject to risks associated with competition from foreign and domestic manufacturers that have excess capacity, labor advantages and other capabilities that may place downward pressure on margins and profitability. Raw material costs for items such as steel, lumber, concrete, aluminum and resin have recently increased significantly and may continue to increase. Our manufacturers may not be able to pass on the cost of such increases to their respective customers. Each of our manufacturing companies has significant customers and concentrated sales to such customers. If our relationships with significant customers should change materially, it would be difficult to immediately and profitably replace lost sales. We believe the demand for wind towers that we manufacture will depend primarily on the existence of either renewable portfolio standards or a federal production tax credit for wind energy.

HEALTH SERVICES

Changes in the rates or methods of third-party reimbursements for our diagnostic imaging services could result in reduced demand for those services or create downward pricing pressure, which would decrease our revenues and earnings.

Our health services businesses derive significant revenue from direct billings to customers and third-party payors such as Medicare, Medicaid, managed care and private health insurance companies for our diagnostic imaging services. Moreover, customers who use our diagnostic imaging services generally rely on reimbursement from third-party payors. Adverse changes in the rates or methods of third-party reimbursements could reduce the number of procedures for which we or our customers can obtain reimbursement or the amounts reimbursed to us or our customers.

Our health services operations has a dealership and other agreements with Philips Medical from which it derives significant revenues from the sale and service of Philips Medical diagnostic imaging equipment.

This agreement can be terminated on 180 days written notice by either party for any reason. It also includes other compliance requirements. If this agreement were terminated within the notice provisions or we were not able to renew such agreements or comply with the agreement, the financial results of our health services operations would be adversely affected.

Technological change in the diagnostic imaging industry could reduce the demand for diagnostic imaging services and require our health services operations to incur significant costs to upgrade its equipment.

Although we believe substantially all of our diagnostic imaging systems can be upgraded to maintain their state-of-the-art character, the development of new technologies or refinements of existing technologies might make our existing systems technologically or economically obsolete, or cause a reduction in the value of, or reduce the need for, our systems.

Actions by regulators of our health services operations could result in monetary penalties or restrictions in our health services operations.

Our health services operations are subject to federal and state regulations relating to licensure, conduct of operations, ownership of facilities, addition of facilities and services and payment of services. Our failure to comply with these regulations, or our inability to obtain and maintain necessary regulatory approvals, may result in adverse actions by regulators with respect to our health services operations, which may include civil and criminal penalties, damages, fines, injunctions, operating restrictions or suspension of operations. Any such action could adversely affect our financial results. Courts and regulatory authorities have not fully interpreted a significant number of these laws and regulations, and this uncertainty in interpretation increases the risk that we may be found to be in violation. Any action brought against us for violation of these laws or regulations, even if successfully defended, may result in significant legal expenses and divert management’s attention from the operation of our businesses.

FOOD INGREDIENT PROCESSING

Our company that processes dehydrated potato flakes, flour and granules competes in a highly competitive market, and is dependent on adequate sources of potatoes for processing.

The market for processed, dehydrated potato flakes, flour and granules is highly competitive. The profitability and success of our potato processing company is dependent on superior product quality, competitive product pricing, strong customer relationships, raw material costs, natural gas prices and availability and customer demand for finished goods. In most product categories, our company competes with numerous manufacturers of varying sizes in the United States.

The principal raw material used by our potato processing company is off-grade potatoes from growers. These potatoes are unsuitable for use in other markets due to imperfections. They are not subject to the United States Department of Agriculture’s general requirements and expectations for size, shape or color. While our food ingredient processing company has processing capabilities in three geographically distinct growing regions, there can be no assurance it will be able to obtain raw materials due to poor growing conditions, a loss of key growers and other factors. A loss of raw materials or the necessity of paying much higher prices for raw materials or natural gas could adversely affect the financial performance of this company. Fluctuations in foreign currency exchange rates could have a negative impact on our potato processing company’s net income and competitive position because approximately 25% of its sales are outside the United States and the Canadian plant pays its operating expenses in Canadian dollars.

We currently have $24.2 million of goodwill recorded on our balance sheet related to the acquisition of IPH in 2004. If current conditions of low sales volumes and prices, high energy costs, increasing raw material costs and the increasing value of the Canadian dollar relative to the U.S. dollar persist and operating margins do not improve according to our projections, the reductions in anticipated cash flows from this business may indicate

that its fair value is less than its book value resulting in an impairment of goodwill and a corresponding charge against earnings.

OTHER BUSINESS OPERATIONS

Our transportation company may be unable to maintain profitable operations if economic conditions restrict its ability to recover the increasing costs of fuel, insurance and labor supplies.

We currently have $6.7 million of goodwill recorded on our balance sheet related to the acquisition of E.W. Wylie Corporation (Wylie), our flatbed trucking company. Reductions in anticipated cash flows from transportation operations may indicate that the fair value of Wylie is less than its book value resulting in an impairment of goodwill and a corresponding charge against earnings.

Our construction companies may be unable to properly bid and perform on projects.

The profitability and success of our construction companies require us to identify, estimate and timely bid on profitable projects. The quantity and quality of projects up for bids at any time is uncertain. Additionally, once a project is awarded, we must be able to perform within cost estimates that were set when the bid was submitted and accepted. A significant failure or an inability to properly bid or perform on projects could lead to adverse financial results for our construction companies.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

At December 31, 2005 we had limited exposure to market risk associated with interest rates and commodity prices and limited exposure to market risk associated with changes in foreign currency exchange rates. Outstanding trade accounts receivable of the Canadian operations of IPH are not at risk of valuation change due to changes in foreign currency exchange rates because the Canadian company transacts all sales in U.S. dollars. However, IPH does have market risk related to changes in foreign currency exchange rates because approximately 25% of IPH sales are outside the United States and the Canadian operations of IPH pays its operating expenses in Canadian dollars.

The majority of our consolidated long-term debt has fixed interest rates. The interest rate on variable rate long-term debt is reset on a periodic basis reflecting current market conditions. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt. As of December 31, 2005 we had $22.0 million of long-term debt subject to variable interest rates. Assuming no change in our financial structure, if variable interest rates were to average one percentage point higher or lower than the average variable rate on December 31, 2005, interest expense and pretax earnings would change by approximately $220,000.

We have not used interest rate swaps to manage net exposure to interest rate changes related to our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial instruments only to the extent considered necessary to meet our stated objectives. We do not enter into interest rate transactions for speculative or trading purposes.

The plastics companies are exposed to market risk related to changes in commodity prices for PVC resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, margins and sales volume have been higher and when resin prices are falling, sales volumes and margins have been lower. Gross margins also

decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or to assume that historical trends will continue.

Our energy services subsidiary markets natural gas to approximately 160 retail customers. Some of these customers are served under fixed-price contracts. There is price risk associated with a limited number of these fixed-price contracts since the corresponding cost of natural gas is not immediately locked in. However, any price risk associated with these contracts is within the acceptable risk parameters established in our risk management policy. We do not consider this price risk to be material. These contracts call for the physical delivery of natural gas and are considered executory contracts for accounting purposes. Current accounting guidance requires losses on firmly committed executory contracts to be recognized when realized.

Our energy services subsidiary has entered into over-the-counter natural gas forward swap transactions that qualify as derivatives subject to mark-to-market accounting under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Although our energy services subsidiary manages its risk by balancing its position in these transactions relative to its market position in the contracts entered into for physical delivery, these swap transactions do not qualify for the normal purchases and sales exception nor do they qualify for hedge accounting treatment under SFAS No. 133. These contracts are held for trading purposes with both realized and unrealized net gains and losses reflected in revenue on our consolidated statement of income for the year ended December 31, 2005 in accordance with the guidance provided in EITF 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.

The following tables show the effect of marking-to-market our energy services subsidiary’s forward natural gas swap transactions on our consolidated balance sheet as of December 31, 2005 and the change in our consolidated balance sheet position from December 31, 2004 to December 31, 2005:

(in thousands)	December 31, 2005
Current asset — marked-to-market gain	$	825
Current liability — marked-to-market loss		(851	)
Net fair value of marked-to-market gas contracts	$	(26	)

	Year ended
(in thousands)	December 31, 2005
Fair value at beginning of year	$	134
Amount realized on contracts entered into in 2004 and settled in 2005		(134	)
Changes in fair value of contracts entered into in 2004		—
Net fair value of contracts entered into in 2004 at year end 2005		—
Changes in fair value of contracts entered into in 2005		(26	)
Net fair value at end of year	$	(26	)

The $26,000 in recognized but unrealized net loss on these forward natural gas swap transactions marked-to-market on December 31, 2005 is expected to be realized on settlement in the first quarter of 2006.

We have minimal credit risk associated with the nonperformance or nonpayment by counterparties to these forward gas swap transactions as we have only one major counterparty to these transactions and this counterparty has a high investment grade credit rating.

The electric utility has market and credit risk associated with forward contracts for the purchase and sale of electricity. As of December 31, 2005 the electric utility had recognized, on a pretax basis, $2.9 million in net

unrealized gains on open forward contracts for the purchase and sale of electricity. Due to the nature of electricity and the physical aspects of the electricity transmission system, unanticipated events affecting the transmission grid can cause transmission constraints that result in unanticipated gains or losses in the process of settling transactions.

The market prices used to value the electric utility’s forward contracts for the purchases and sales of electricity are determined by survey of counterparties by the electric utility’s power services’ personnel responsible for contract pricing and are benchmarked to regional hub prices as published in Megawatt Daily and as observed in the Intercontinental Exchange trading system. Of the forward energy contracts that are marked-to-market as of December 31, 2005, 91% of the forward purchases of electricity had offsetting sales in terms of volumes and delivery periods. The amount of net unrealized marked-to-market losses recognized on forward purchases of electricity not offset by forward sales of electricity as of December 31, 2005 was $269,000.

We have in place an energy risk management policy with a goal to manage, through the use of defined risk management practices, price risk and credit risk associated with wholesale power purchases and sales. With the advent of the MISO Day 2 market in April 2005, several changes were made to the energy risk management policy to recognize new trading opportunities created by this new market. Most of the changes were in new volumetric limits and loss limits to adequately manage the risks associated with these new opportunities. In addition, a Value at Risk (VaR) limit was also implemented to further manage market price risk. Exposure to price risk on any open positions as of December 31, 2005 was not material.

The following tables show the effect of marking-to-market forward contracts for the purchase and sale of electricity on our consolidated balance sheet as of December 31, 2005 and the change in our consolidated balance sheet position from December 31, 2004 to December 31, 2005:

	December 31,
(in thousands)	2005
Current asset — marked-to-market gain	$	8,603
Regulatory asset — deferred marked-to-market loss		1,423
Total assets		10,026
Current liability — marked-to-market loss		(4,185	)
Regulatory liability — deferred marked-to-market gain		(2,925	)
Total liabilities		(7,110	)
Net fair value of marked-to-market energy contracts	$	2,916

	Year ended
(in thousands)	December 31, 2005
Fair value at beginning of year	$	301
Amount realized on contracts entered into in 2004 and settled in 2005		(322	)
Changes in fair value of contracts entered into in 2004		21
Net fair value of contracts entered into in 2004 at year end 2005		—
Changes in fair value of contracts entered into in 2005		2,916
Net fair value at end of year	$	2,916

The $2.9 million in recognized but unrealized net gains on the forward energy purchases and sales marked-to-market on December 31, 2005 is expected to be realized on settlement as scheduled over the following quarters in the amounts listed:

	1st Quarter		2nd Quarter		3rd Quarter
(in thousands)	2006		2006		2006		Total
Net gain	$	2,281	$	527	$	108	$	2,916

We have credit risk associated with the nonperformance or nonpayment by counterparties to our forward energy purchases and sales agreements. We have established guidelines and limits to manage credit risk associated with wholesale power purchases and sales. Specific limits are determined by a counterparty’s financial strength. Our credit risk with our largest counterparty on delivered and marked-to-market forward contracts as of December 31, 2005 was $2.3 million. As of December 31, 2005 we had a net credit risk exposure of $7.1 million from 13 counterparties with investment grade credit ratings.

The $7.1 million credit risk exposure includes net amounts due to the electric utility on receivables/payables from completed transactions billed and unbilled plus marked-to-market gains/losses on forward contracts for the purchase and sale of electricity scheduled for delivery after December 31, 2005. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). There is no exposure at December 31, 2005 to counterparties with credit ratings below investment grade

CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES

Our significant accounting policies are described in note 1 to consolidated financial statements. The discussion and analysis of the financial statements and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.

We use estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, valuation of forward energy contracts, unbilled electric revenues, unscheduled power exchanges, MISO electric market residual load adjustments, service contract maintenance costs, percentage-of-completion and actuarially determined benefits costs. As better information becomes available or actual amounts are known, estimates are revised. Operating results can be affected by revised estimates. Actual results may differ from these estimates under different assumptions or conditions. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of the Board of Directors. The following critical accounting policies affect the more significant judgments and estimates used in the preparation of our consolidated financial statements.

PENSION AND OTHER POSTRETIREMENT BENEFITS OBLIGATIONS AND COSTS

Pension and postretirement benefit liabilities and expenses for our electric utility and corporate employees are determined by actuaries using assumptions about the discount rate, expected return on plan assets, rate of compensation increase and healthcare cost-trend rates. Further discussion of our pension and postretirement benefit plans and related assumptions is included in note 11 to consolidated financial statements.

These benefits, for any individual employee, can be earned and related expenses can be recognized and a liability accrued over periods of up to 40 or more years. These benefits can be paid out for up to 40 or more years after an employee retires. Estimates of liabilities and expenses related to these benefits are among our most critical accounting estimates. Although deferral and amortization of fluctuations in actuarially determined benefit obligations and expenses are provided for when actual results on a year-to-year basis deviate from long-range assumptions, compensation increases and healthcare cost increases or a reduction in the discount rate applied from one year to the next can significantly increase our benefit expenses in the year of the change. Also, a reduction in the expected rate of return on pension plan assets in our funded pension plan or realized rates of return on plan assets that are well below assumed rates of return could result in significant increases in recognized pension benefit expenses in the year of the change or for many years thereafter because actuarial losses can be amortized over the average remaining service lives of active employees.

Effective July 1, 2005 we remeasured our pension and other postretirement benefit plan obligations using the RP-2000 Combined Healthy Mortality table in place of the 1983 Group Annuity Mortality table (GAM ’83) used to measure obligations and determine annual costs under these plans in January 2005. The reason for the remeasurement was to update the mortality table to more accurately reflect current life expectancies of current employees and retirees included in the plans.

The pension benefit cost for 2006 for our noncontributory funded pension plan is expected to be $5.0 million compared to $4.4 million in 2005. The estimated discount rate used to determine annual benefit cost accruals will increase to 5.75% in 2006 from a composite rate of 5.625% used in 2005. In selecting the discount rate, we use the yield of a fixed income debt security, which has a rating of “Aa” published by a recognized rating agency along with a bond matching model as a basis to determine the rate.

Subsequent increases or decreases in actual rates of return on plan assets over assumed rates or increases or decreases in the discount rate or rate of increase in future compensation levels could significantly change projected costs. For 2005, all other factors being held constant: a 0.25 increase (or decrease) in the discount rate would have decreased (or increased) our 2005 pension benefit cost by $550,000; a 0.25 increase (or decrease) in the assumed rate of increase in future compensation levels would have increased (or decreased) our 2005 pension benefit cost by $520,000; a 0.25 increase (or decrease) in the expected long-term rate of return on plan assets would have decreased (or increased) our 2005 pension benefit cost by $360,000.

Increases or decreases in the discount rate or in retiree healthcare cost inflation rates could significantly change our projected postretirement healthcare benefit costs. A 0.25 increase (or decrease) in the discount rate would have decreased (or increased) our 2005 postretirement medical benefit costs by $105,000. See note 11 to consolidated financial statements for the cost impact of a change in medical cost inflation rates.

We believe the estimates made for our pension and other postretirement benefits are reasonable based on the information that is known at the point in time the estimates are made. These estimates and assumptions are subject to a number of variables and are subject to change.

REVENUE RECOGNITION

Our construction companies and two of our manufacturing companies record operating revenues on a percentage-of-completion basis for fixed-price construction contracts. The method used to determine the progress of completion is based on the ratio of labor costs incurred to total estimated labor costs at our wind tower manufacturer, square footage completed to total bid square footage for certain floating dock projects and costs incurred to total estimated costs on all other construction projects. The duration of the majority of these contracts is less than a year. Revenues recognized on jobs in progress as of December 31, 2005 were $204 million.

Expected losses on jobs in progress at year-end 2005 have been recognized. We believe the accounting estimate related to the percentage-of-completion accounting on uncompleted contracts is critical to the extent that any underestimate of total expected costs on fixed-price construction contracts could result in reduced profit margins being recognized on these contracts at the time of completion.

FORWARD ENERGY CONTRACTS CLASSIFIED AS DERIVATIVES

Our electric utility’s forward contracts for the purchase and sale of electricity and our energy services company’s forward natural gas swap transactions are derivatives subject to mark-to-market accounting under accounting principles generally accepted in the United States. The market prices used to value the electric utility’s forward contracts for the purchases and sales of electricity are determined by survey of counterparties by the electric utility’s power services’ personnel responsible for contract pricing and are benchmarked to regional hub prices as published in Megawatt Daily and as observed in the Intercontinental Exchange trading system and, as such, are estimates. Of the forward electric energy contracts that are marked-to-market as of December 31, 2005, 91% of the forward energy purchases have offsetting sales in terms of volumes and delivery periods. The amount of net unrealized marked-to-market losses recognized on forward energy purchases that are not offset by forward energy sales as of December 31, 2005 was $269,000. All of the forward energy contracts for the purchase and sale of electricity marked-to-market as of December 31, 2005 are scheduled for settlement prior to September 1, 2006.

ALLOWANCE FOR DOUBTFUL ACCOUNTS

Our operating companies encounter risks associated with sales and the collection of the associated accounts receivable. As such, they record provisions for accounts receivable that are considered to be uncollectible. In order to calculate the appropriate monthly provision, the operating companies primarily utilize historical rates of accounts receivables written off as a percentage of total revenue. This historical rate is applied to the current revenues on a monthly basis. The historical rate is updated periodically based on events that may change the rate such as a significant increase or decrease in collection performance and timing of payments as well as the calculated total exposure in relation to the allowance. Periodically, operating companies compare identified credit risks with allowances that have been established using historical experience and adjust allowances accordingly. In circumstances where an operating company is aware of a specific customer’s inability to meet financial obligations, the operating company records a specific allowance for bad debts to reduce the net recognized receivable to the amount it reasonably believes will be collected.

We believe the accounting estimates related to the allowance for doubtful accounts is critical because the underlying assumptions used for the allowance can change from period to period and could potentially cause a material impact to the income statement and working capital.

During 2005, $2.0 million of bad debt expense from continuing operations (0.19% of total 2005 revenue of $1.05 billion) was recorded and the allowance for doubtful accounts was $3.5 million (2.6% of trade accounts receivable) as of December 31, 2005. General economic conditions and specific geographic concerns are major factors that may affect the adequacy of the allowance and may result in a change in the annual bad debt expense. An increase or decrease of one percentage point in our consolidated allowance for doubtful accounts based on outstanding receivables at December 31, 2005 would result in a $1.3 million increase or decrease in bad debt expense.

Although an estimated allowance for doubtful accounts on our operating companies’ accounts receivable is provided for, the allowance for doubtful accounts on the electric segment’s wholesale electric sales is insignificant in proportion to annual revenues from these sales. The electric segment has not experienced a bad debt related to wholesale electric sales due largely to stringent risk management criteria related to these sales. However, nonpayment on a single wholesale electric sale could result in a significant bad debt expense.

DEPRECIATION EXPENSE AND DEPRECIABLE LIVES

The provisions for depreciation of electric utility property for financial reporting purposes are made on the straight-line method based on the estimated service lives (5 to 65 years) of the properties. Such provisions as a percent of the average balance of depreciable electric utility property were 2.74% in 2005, 2.77% in 2004 and 3.07% in 2003. Depreciation rates on electric utility property are subject to annual regulatory review and approval, and depreciation expense is recovered through rates set by ratemaking authorities. Although the useful lives of electric utility properties are estimated, the recovery of their cost is dependent on the ratemaking process. Deregulation of the electric industry could result in changes to the estimated useful lives of electric utility property that could impact depreciation expense.

Property and equipment of our nonelectric operations are carried at historical cost or at the current appraised value if acquired in a business combination accounted for under the purchase method of accounting and are depreciated on a straight-line basis over useful lives (3 to 40 years) of the related assets. We believe that the lives and methods of determining depreciation are reasonable, however, changes in economic conditions affecting the industries in which our nonelectric companies operate or innovations in technology could result in a reduction of the estimated useful lives of our nonelectric operating companies’ property, plant and equipment or in an impairment write-down of the carrying value of these properties.

TAXATION

We are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations to estimate our obligations to taxing authorities. These tax obligations include income, real estate and use taxes. These judgments include reserves for potential adverse outcomes regarding tax positions that we have taken. While we believe the resulting tax reserve balances as of December 31, 2005 reflect the most likely probable expected outcome of these tax matters in accordance with SFAS No. 5, Accounting for Contingencies, and SFAS No. 109, Accounting for Income Taxes, the ultimate outcome of such matters could result in additional adjustments to our consolidated financial statements. However, we do not believe such adjustments would be material based on items currently reserved for.

Deferred income taxes are provided for revenue and expenses which are recognized in different periods for income tax and financial reporting purposes. We assess our deferred tax assets for recoverability based on both historical and anticipated earnings levels. We have not recorded a valuation allowance related to the probability of recovery of our deferred tax assets as we believe reductions in tax payments related to these assets will be fully realized in the future.

ASSET IMPAIRMENT

We are required to test for asset impairment relating to property and equipment whenever events or changes in circumstances indicate that the carrying value of an asset might not be recoverable. We apply SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in order to determine whether or not an asset is impaired. This standard requires an impairment analysis when indicators of impairment are present. If such indicators are present, the standard requires that if the sum of the future expected cash flows from a company’s asset, undiscounted and without interest charges, is less than the carrying value, an asset impairment must be recognized in the financial statements. The amount of the impairment is the difference between the fair value of the asset and the carrying value of the asset.

We believe the accounting estimates related to an asset impairment are critical because they are highly susceptible to change from period to period reflecting changing business cycles and require management to make assumptions about future cash flows over future years and the impact of recognizing an impairment could have a significant effect on operations. Management’s assumptions about future cash flows require significant judgment because actual operating levels have fluctuated in the past and are expected to continue to do so in the future.

As of December 31, 2005 an assessment of the carrying values of our long-lived assets and other intangibles indicated that these assets were not impaired.

GOODWILL IMPAIRMENT

Goodwill is required to be evaluated annually for impairment, according to SFAS No. 142, Goodwill and Other Intangible Assets. The standard requires a two-step process be performed to analyze whether or not goodwill has been impaired. Step one is to test for potential impairment, and requires that the fair value of the reporting unit be compared to its book value including goodwill. If the fair value is higher than the book value, no impairment is recognized. If the fair value is lower than the book value, a second step must be performed. The second step is to measure the amount of impairment loss, if any, and requires that a hypothetical purchase price allocation be done to determine the implied fair value of goodwill. This fair value is then compared to the carrying value of goodwill. If the implied fair value is lower than the carrying value, an impairment must be recorded.

We believe accounting estimates related to goodwill impairment are critical because the underlying assumptions used for the discounted cash flow can change from period to period and could potentially cause a material impact to the income statement. Management’s assumptions about inflation rates and other internal and external economic conditions, such as earnings growth rate, require significant judgment based on fluctuating rates and expected revenues. Additionally, SFAS No. 142 requires goodwill be analyzed for impairment on an annual basis using the assumptions that apply at the time the analysis is updated.

We evaluate goodwill for impairment on an annual basis and as conditions warrant. As of December 31, 2005 an assessment of the carrying values of our goodwill indicated no impairment.

PURCHASE ACCOUNTING

We account for our acquisitions under the purchase method of accounting and, accordingly, the acquired assets and liabilities assumed are recorded at their respective fair values. The excess of purchase price over the fair value of the assets acquired and liabilities assumed is recorded as goodwill. The recorded values of assets and liabilities are based on third party estimates and valuations when available. The remaining values are based on management’s judgments and estimates, and, accordingly, our consolidated financial position or results of operations may be affected by changes in estimates and judgments.

Acquired assets and liabilities assumed that are subject to critical estimates include property, plant and equipment and intangible assets.

The fair value of property, plant and equipment is based on valuations performed by qualified internal personnel and/or outside appraisers. Fair values assigned to plant and equipment are based on several factors including the age and condition of the equipment, maintenance records of the equipment and auction values for equipment with similar characteristics at the time of purchase.

Intangible assets are identified and valued using the guidelines of SFAS No. 141, Business Combinations. The fair value of intangible assets is based on estimates including royalty rates, customer attrition rates and estimated cash flows.

While the allocation of purchase price is subject to a high degree of judgment and uncertainty, we do not expect the estimates to vary significantly once an acquisition is complete. We believe our estimates have been reasonable in the past as there have been no significant valuation adjustments to the final allocation of purchase price.

KEY ACCOUNTING PRONOUNCEMENTS

SFAS No. 151, Inventory Costs an amendment of ARB No. 43, Chapter 4, was issued in November 2004 to clarify that abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) should be recognized as current-period charges. This statement also requires that allocation of fixed production overheads to the costs of converting materials into finished products be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005 with earlier application permitted. The early application of this standard did not have a material effect on our consolidated net income, financial position or cash flows.

SFAS No. 123(R) (revised 2004), Share-Based Payment, issued in December 2004 is a revision of SFAS No. 123, Accounting for Stock-based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. We currently report our stock-based compensation under the requirements of APB Opinion No. 25 and furnish related pro forma footnote information required under SFAS No. 123. Under SFAS No. 123(R), we will be required to record our stock-based compensation as an expense on our income statement over the period earned based on the fair value of the stock or options awarded on their grant date. SFAS No.123(R) becomes effective, and was adopted by the company on a modified prospective basis, on January 1, 2006. The application of SFAS No. 123(R) reporting requirements will result in recording compensation expense of approximately $160,000, net-of-tax, in 2006 for our currently outstanding non-vested stock options. Additionally, the application of SFAS No. 123(R) reporting requirements will result in recording compensation expense of approximately $240,000, net-of-tax, in 2006 for the 15% discount offered under our Employee Stock Purchase Program (ESPP), if our shareholders approve the Board of Directors’ authorization of additional shares for the ESPP.

FASB Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations, is an interpretation of SFAS No. 143 on accounting for obligations associated with the retirement of tangible, long-lived assets. The revised guidance on conditional obligations is effective for fiscal years ending after December 15, 2005. The interpretation provides clarification and further guidance about when sufficient information exists to reasonably estimate the fair value of legal obligations in circumstances where uncertainty exists about the timing and (or) methods of settlement of a conditional asset retirement obligation. We evaluated our legal obligations in light of the additional guidance provided by this interpretation and determined that our previously recognized obligations did not change under this interpretation. However, we did determine that our transmission and distribution lines rights-of-way, including those with indeterminate lives, are not subject to the provisions of SFAS No. 143 because they are intangible assets. We also determined that there are no legal retirement obligations associated with structures using those rights-of-way.

SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, was issued in December 2004. This statement addresses the measurement of exchanges of nonmonetary assets. It eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29, Accounting for Nonmonetary Transactions, and replaces it with an exception for exchanges that do not have commercial substance. This statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this statement shall be effective and applied prospectively for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005 with earlier application permitted. The early application of this standard did not have a material effect on our consolidated net income, financial position or cash flows.

SFAS No. 154, Accounting for Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3, was issued in May 2005. This statement provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. This statement also provides guidance for determining whether retrospective application of a change in accounting principle is impracticable and for reporting a change when retrospective application is impracticable. This statement shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, with early adoption permitted. We do not expect the application of the requirements of SFAS No. 154 to have a material effect on our consolidated net income, financial position or cash flows.

Management’s Report Regarding Internal Controls Over Financial Reporting

Management is responsible for the preparation and integrity of the consolidated financial statements and representations in this annual report. The consolidated financial statements of Otter Tail Corporation have been prepared in conformity with generally accepted accounting principles applied on a consistent basis and include some amounts that are based on informed judgments and best estimates and assumptions of management.

In order to assure the consolidated financial statements are prepared in conformance with generally accepted accounting principles, management is responsible for establishing and maintaining adequate internal controls over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). These internal controls are designed only to provide reasonable assurance, on a cost-effective basis, that transactions are carried out in accordance with management’s authorizations and assets are safeguarded against loss from unauthorized use or disposition.

Management has completed its assessment of the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2005. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework to conduct the required assessment of the effectiveness of the Company’s internal controls over financial reporting.

Management included Idaho Pacific Holdings, Inc. (IPH), acquired in August 2004, in its assessment of the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2005. IPH was not included in management’s assessment of the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2004 based on guidelines established by the Securities and Exchange Commission that allow newly acquired companies to be excluded from assessment in the year they are acquired. In connection with the implementation of MISO Day 2 markets in 2005, the Company implemented new processes and modified existing processes to facilitate participation in, and resultant settlements within the MISO market. Apart from these changes, there have not been any other changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the fiscal year to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Based on this assessment, we believe that, as of December 31, 2005 the Company’s internal controls over financial reporting are effective based on those criteria.

The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has audited our consolidated financial statements included in this annual report and has also issued an attestation report on management’s assessment of the Company’s internal controls over financial reporting.

/s/ John Erickson

John Erickson
President and Chief Executive Officer

/s/ Kevin Moug

Kevin Moug
Chief Financial Officer and Treasurer

February 20, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE SHAREHOLDERS OF OTTER TAIL CORPORATION

We have audited the accompanying consolidated balance sheets and statements of capitalization of Otter Tail Corporation and its subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of income, common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. We also have audited management’s assessment, included in the accompanying Management’s Report Regarding Internal Controls Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any

evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota
February 20, 2006

Otter Tail Corporation

Consolidated Statements of Income—For the Years Ended December 31

( in thousands, except per-share amounts)	2005			2004		2003
Operating revenues	$	1,046,408		$	857,362	$	724,288
Operating expenses
Production fuel		55,927			52,056		51,163
Purchased power — system use		58,828			40,098		36,002
Electric operation and maintenance expenses		99,904			85,361		87,186
Cost of goods sold (excludes depreciation; included below)		566,647			464,009		355,777
Other nonelectric expenses		110,004			86,542		72,624
Goodwill impairment loss		1,003			—		—
Depreciation and amortization		46,458			43,471		42,994
Property taxes — electric operations		10,043			10,411		9,598
Total operating expenses		948,814			781,948		655,344
Operating income		97,594			75,414		68,944
Other income		1,786			793		1,111
Interest charges		18,558			18,128		17,668
Income from continuing operations before income taxes		80,822			58,079		52,387
Income taxes — continuing operations		27,967			17,447		14,162
Net income from continuing operations		52,855			40,632		38,225
Discontinued operations
Income (loss) from discontinued operations net of taxes of $(221) in 2005, $1,040 in 2004 and $768 in 2003		(308	)		1,563		1,431
Net gain on disposition of discontinued operations net of taxes of $5,831 in 2005		10,004			—		—
Net income from discontinued operations		9,696			1,563		1,431
Net Income		62,551			42,195		39,656
Preferred dividend requirements		735			736		735
Earnings available for common shares	$	61,816		$	41,459	$	38,921
Average number of common shares outstanding—basic		29,223			26,089		25,673
Average number of common shares outstanding—diluted		29,348			26,207		25,826
Basic earnings per share:
Continuing operations (net of preferred dividend requirements)	$	1.79		$	1.53	$	1.46
Discontinued operations		0.33			0.06		0.06
	$	2.12		$	1.59	$	1.52
Diluted earnings per share:
Continuing operations (net of preferred dividend requirements)	$	1.78		$	1.52	$	1.45
Discontinued operations		0.33			0.06		0.06
	$	2.11		$	1.58	$	1.51
Dividends per common share	$	1.12		$	1.10	$	1.08

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Balance Sheets, December 31

(in thousands)	2005		2004
Assets
Current assets
Cash and cash equivalents	$	5,430	$	—
Accounts receivable:
Trade (less allowance for doubtful accounts of $3,493 for 2005 and $2,730 for 2004)		128,355		116,141
Other		11,790		9,872
Inventories		88,677		72,504
Deferred income taxes		6,871		4,852
Accrued utility revenues		22,892		15,344
Costs and estimated earnings in excess of billings		21,542		18,145
Other		17,301		7,800
Assets of discontinued operations		2,317		30,937
Total current assets		305,175		275,595
Investments and other assets		33,824		42,650
Goodwill—net		98,110		92,196
Other intangibles—net		21,160		19,600
Deferred debits
Unamortized debt expense and reacquisition premiums		6,520		7,291
Regulatory assets and other deferred debits		19,616		16,692
Total deferred debits		26,136		23,983
Plant
Electric plant in service		910,766		890,200
Nonelectric operations		228,548		208,311
Total		1,139,314		1,098,511
Less accumulated depreciation and amortization		459,438		436,856
Plant—net of accumulated depreciation and amortization		679,876		661,655
Construction work in progress		17,215		18,469
Net plant		697,091		680,124
Total	$	1,181,496	$	1,134,148

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Balance Sheets, December 31

(in thousands, except share data)	2005			2004
Liabilities and Equity
Current liabilities
Short-term debt	$	16,000		$	39,950
Current maturities of long-term debt		3,340			6,016
Accounts payable		106,570			84,433
Accrued salaries and wages		24,326			17,330
Accrued federal and state income taxes		8,776			3,700
Other accrued taxes		12,620			11,391
Other accrued liabilities		14,975			10,417
Liabilities of discontinued operations		372			8,585
Total current liabilities		186,979			181,822
Pension benefit liability		23,216			16,703
Other postretirement benefits liability		26,982			25,053
Other noncurrent liabilities		18,683			11,874
Commitments (note 8)
Deferred credits
Deferred income taxes		113,737			121,301
Deferred investment tax credit		9,327			10,477
Regulatory liabilities		61,624			56,909
Other		1,500			1,662
Total deferred credits		186,188			190,349
Capitalization (page 40)
Long-term debt, net of current maturities		258,260			261,805
Class B stock options of subsidiary		1,258			1,832
Cumulative preferred shares		15,500			15,500
Common shares, par value $5 per share—authorized, 50,000,000 shares; outstanding, 2005—29,401,223 shares; 2004—28,976,919 shares		147,006			144,885
Premium on common shares		96,768			87,865
Unearned compensation		(1,720	)		(2,577	)
Retained earnings		228,515			199,427
Accumulated other comprehensive loss		(6,139	)		(390	)
Total common equity		464,430			429,210
Total capitalization		739,448			708,347
Total	$	1,181,496		$	1,134,148

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Common Shareholders’ Equity

																Accumulated
	Common			Par value,			Premium on									other
	shares			common			common			Unearned			Retained			comprehensive			Total
(in thousands, except common shares outstanding)	outstanding			shares			shares			compensation			earnings			income/(loss)			equity
Balance, December 31, 2002		25,592,160		$	127,961		$	24,135		$	(1,946	)	$	175,304		$	(11,989	)	$	313,465
Common stock issuances		140,621			703			2,793			(2,477	)								1,019
Common stock retirements		(8,967	)		(45	)		(225	)											(270	)
Amortization of unearned compensation—stock awards											1,110									1,110
Comprehensive income:
Net income														39,656						39,656
Minimum pension liability adjustment																	7,560			7,560
Total comprehensive income																				47,216
Tax benefit for exercise of stock options								111												111
Purchase stock for employee purchase plan								(299	)											(299	)
Cumulative preferred dividends														(735	)					(735	)
Common dividends														(27,730	)					(27,730	)
Balance, December 31, 2003		25,723,814		$	128,619		$	26,515		$	(3,313	)	$	186,495		$	(4,429	)		333,887
Common stock issuances, net of expenses		3,266,266			16,332			63,373			(566	)								79,139
Common stock retirements		(13,161	)		(66	)		(283	)											(349	)
Amortization of unearned compensation—stock awards											1,302									1,302
Comprehensive income:
Net income														42,195						42,195
Unrealized loss on marketable equity securities																	(14	)		(14	)
Foreign currency exchange translation																	1,014			1,014
Minimum pension liability adjustment																	3,039			3,039
Total comprehensive income																				46,234
Tax benefit for exercise of stock options								92												92
Valuation of stock options of subsidiary acquired in 2004								(1,832	)											(1,832	)
Cumulative preferred dividends														(735	)					(735	)
Common dividends														(28,528	)					(28,528	)
Balance, December 31, 2004		28,976,919		$	144,885		$	87,865		$	(2,577	)	$	199,427		$	(390	)	$	429,210
Common stock issuances, net of expenses		456,211			2,281			8,483			(529	)								10,235
Common stock retirements		(31,907	)		(160	)		(756	)											(916	)
Amortization of unearned compensation—stock awards											1,386									1,386
Comprehensive income:
Net income														62,551						62,551
Unrealized loss on marketable equity securities																	(23	)		(23	)
Foreign currency exchange translation																	437			437
Minimum pension liability adjustment																	(6,163	)		(6,163	)
Total comprehensive income																				56,802
Tax benefit for exercise of stock options								596												596
Stock incentive plan performance award accrual								943												943
Purchase stock for employee purchase plan								(363	)											(363	)
Cumulative preferred dividends														(735	)					(735	)
Common dividends														(32,728	)					(32,728	)
Balance, December 31, 2005		29,401,223		$	147,006		$	96,768		$	(1,720	)	$	228,515		$	(6,139)	(a)	$	464,430

(a) Accumulated other comprehensive loss on December 31, 2005 is comprised of the following:

(in thousands)	Before Tax			Tax Effect			Net-of-tax
Minimum pension liability adjustment	$	(12,588	)	$	5,035		$	(7,553	)
Foreign currency exchange translation		2,420			(968	)		1,452
Unrealized loss on marketable equity securities		(63	)		25			(38	)
Net accumulated other comprehensive loss	$	(10,231	)	$	4,092		$	(6,139	)

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Cash Flows—For the Years Ended December 31

(in thousands)	2005			2004			2003
Cash flows from operating activities
Net income	$	62,551		$	42,195		$	39,656
Adjustments to reconcile net income to net cash provided by operating activities:
Net gain on sale of discontinued operations		(10,004	)		—			—
Loss (income) from discontinued operations		308			(1,563	)		(1,431	)
Depreciation and amortization		46,458			43,471			42,994
Deferred investment tax credit		(1,150	)		(1,152	)		(1,152	)
Deferred income taxes		(9,223	)		3,950			3,125
Change in deferred debits and other assets		9,868			(1,641	)		(3,173	)
Discretionary contribution to pension plan		(4,000	)		(4,000	)		—
Change in noncurrent liabilities and deferred credits		1,321			2,110			8,026
Allowance for equity (other) funds used during construction		(723	)		(716	)		(1,355	)
Change in derivatives net of regulatory deferral		(2,455	)		1,621			(2,057	)
Other—net		3,506			1,430			1,643
Cash (used for) provided by current assets and current liabilities:
Change in receivables		(13,482	)		(9,808	)		(19,137	)
Change in inventories		(12,500	)		(6,894	)		(12,619	)
Change in other current assets		(13,882	)		(15,386	)		(2,012	)
Change in payables and other current liabilities		36,021			1,679			18,624
Change in interest and income taxes payable		(2,256	)		(966	)		5,182
Net cash provided by continuing operations		90,358			54,330			76,314
Net cash provided by discontinued operations		5,442			1,971			641
Net cash provided by operating activities		95,800			56,301			76,955
Cash flows from investing activities
Capital expenditures		(59,969	)		(49,484	)		(48,783	)
Proceeds from disposal of noncurrent assets		4,193			5,844			1,563
Acquisitions—net of cash acquired		(11,223	)		(69,069	)		(12,896	)
Decreases (increases) in other investments		4,171			(5,099	)		1,071
Net cash used in investing activities – continuing operations		(62,828	)		(117,808	)		(59,045	)
Net proceeds from sale of discontinued operations		34,185			—			—
Net cash provided by (used in) investing activities – discontinued operations		602			(1,310	)		(1,363	)
Net cash used in investing activities		(28,041	)		(119,118	)		(60,408	)
Cash flows from financing activities
Change in checks written in excess of cash		(3,329	)		3,458			—
Net short-term (repayments) borrowings		(23,950	)		9,950			—
Proceeds from issuance of common stock, net of issuance expenses		9,690			78,780			1,072
Payments for retirement of common stock and Class B stock of subsidiary		(939	)		(349	)		—
Proceeds from issuance of long-term debt, net of issuance expenses		228			4,065			18,442
Payments for retirement of long-term debt		(7,232	)		(9,061	)		(8,189	)
Dividends paid		(33,463	)		(29,263	)		(28,937	)
Net cash (used in) provided by financing activities – continuing operations		(58,995	)		57,580			(17,612	)
Net cash used in financing activities – discontinued operations		(2,996	)		(1,679	)		(1,239	)
Net cash (used in) provided by financing activities		(61,991	)		55,901			(18,851	)
Effect of foreign exchange rate fluctuations on cash		(338	)		(794	)		—
Net change in cash and cash equivalents		5,430			(7,710	)		(2,304	)
Cash and cash equivalents at beginning of year – continuing operations		—			7,710			10,014
Cash and cash equivalents at end of year – continuing operations	$	5,430		$	—		$	7,710
Supplemental disclosures of cash flow information
Cash paid during the year from continuing operations for:
Interest (net of amount capitalized)	$	17,670		$	16,443		$	16,563
Income taxes	$	39,212		$	16,204		$	7,956
Cash paid during the year from discontinued operations for:
Interest	$	86		$	111		$	218
Income taxes	$	659		$	840		$	481

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Capitalization, December 31

(in thousands, except share data)	2005		2004
Long-term debt
Lombard US Equipment Finance note, variable, 5.484% at December 31, 2005, due October 2, 2010	$	11,643	$	13,971
Senior debentures 6.375%, due December 1, 2007		50,000		50,000
Senior notes 6.63%, due December 1, 2011		90,000		90,000
Insured senior notes 5.625%, due October 1, 2017		40,000		40,000
Senior notes 6.80%, due October 1, 2032		25,000		25,000
Pollution control refunding revenue bonds, variable, 3.91% at December 31, 2005, due December 1, 2012		10,400		10,400
Grant County, South Dakota pollution control refunding revenue bonds 4.65%, due September 1, 2017		5,185		5,185
Mercer County, North Dakota pollution control refunding revenue bonds 4.85%, due September 1, 2022		20,735		20,735
Obligations of Varistar Corporation:
8.15% five-year term note, retired in April 2005		—		540
7.80% ten-year term note, retired in July 2005		—		1,483
Various up to 9.65% at December 31, 2005		9,235		11,191
Total		262,198		268,505
Less:
Current maturities		3,340		6,016
Unamortized debt discount		598		684
Total long-term debt—continuing operations		258,260		261,805
Class B stock options of subsidiary		1,258		1,832
Cumulative preferred shares—without par value (stated and
liquidating value $100 a share)—authorized 1,500,000 shares;
Series outstanding:
$3.60, 60,000 shares		6,000		6,000
$4.40, 25,000 shares		2,500		2,500
$4.65, 30,000 shares		3,000		3,000
$6.75, 40,000 shares		4,000		4,000
Total preferred		15,500		15,500
Cumulative preference shares—without par value, authorized 1,000,000 shares; outstanding: none
Total common shareholders’ equity		464,430		429,210
Total capitalization	$	739,448	$	708,347

See accompanying notes to consolidated financial statements.

Otter Tail Corporation
Notes to Consolidated Financial Statements
For the years ended December 31, 2005, 2004 and 2003

1. Summary of Significant Accounting Policies

Principles of Consolidation—The consolidated financial statements of Otter Tail Corporation and its wholly-owned subsidiaries (the Company) include the accounts of the following segments: electric, plastics, manufacturing, health services, food ingredient processing and other business operations. See note 2 to the consolidated financial statements for further descriptions of the Company’s business segments. All significant intercompany balances and transactions have been eliminated in consolidation except profits on sales to the regulated electric utility company from nonregulated affiliates, which is in accordance with the requirements of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. These amounts are not material.

Regulation and Statement of Financial Accounting Standards No. 71—As a regulated entity, the Company and the electric utility account for the financial effects of regulation in accordance with SFAS No. 71. This statement allows for the recording of a regulatory asset or liability for costs that will be collected or refunded through the ratemaking process in the future. In accordance with regulatory treatment, the Company defers utility debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. See note 4 for further discussion.

The Company’s regulated business is subject to various state and federal agency regulations. The accounting policies followed by this business are subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the Company’s nonelectric businesses.

Plant, Retirements and Depreciation—Utility plant is stated at original cost. The cost of additions includes contracted work, direct labor and materials, allocable overheads and allowance for funds used during construction (AFC). AFC, a noncash item, is included in utility construction work in progress. The amount of AFC capitalized was $913,000 for 2005, $949,000 for 2004 and $1,970,000 for 2003. The cost of depreciable units of property retired less salvage is charged to accumulated depreciation. Removal costs, when incurred, are charged against the accumulated reserve for estimated removal costs, a regulatory liability. Maintenance, repairs and replacement of minor items of property are charged to operating expenses. The provisions for utility depreciation for financial reporting purposes are made on the straight-line method based on the estimated service lives of the properties. Such provisions as a percent of the average balance of depreciable electric utility property were 2.74% in 2005, 2.77% in 2004 and 3.07% in 2003. Gains or losses on asset dispositions are taken to the accumulated provision for depreciation reserve and impact current and future depreciation rates.

Property and equipment of nonelectric operations are carried at historical cost or at the then-current appraised value if acquired in a business combination accounted for under the purchase method of accounting, and are depreciated on a straight-line basis over the assets estimated useful lives (3 to 40 years). Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of operating income.

Jointly Owned Plants—The consolidated balance sheets include the Company’s ownership interests in the assets and liabilities of Big Stone Plant (53.9%) and Coyote Station (35.0%). The following amounts are included in the December 31, 2005 and 2004 consolidated balance sheets:

	Big Stone			Coyote
(in thousands)	Plant			Station
December 31, 2005
Electric plant in service	$	124,852		$	146,405
Accumulated depreciation		(71,824	)		(77,909	)
Net plant	$	53,028		$	68,496
December 31, 2004
Electric plant in service	$	116,405		$	146,343
Accumulated depreciation		(70,904	)		(75,431	)
Net plant	$	45,501		$	70,912

The Company’s share of direct revenue and expenses of the jointly owned plants is included in operating revenue and expenses in the consolidated statements of income.

Recoverability of Long-Lived Assets—The Company reviews its long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. The Company determines potential impairment by comparing the carrying value of the assets with net cash flows expected to be provided by operating activities of the business or related assets. If the sum of the expected future net cash flows is less than the carrying values, the Company would determine whether an impairment loss should be recognized. An impairment loss would be quantified by comparing the amount by which the carrying value exceeds the fair value of the asset, where fair value is based on the discounted cash flows expected to be generated by the asset.

Income Taxes—Comprehensive interperiod income tax allocation is used for substantially all book and tax temporary differences. Deferred income taxes arise for all temporary differences between the book and tax basis of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect when the temporary differences reverse. The Company amortizes the investment tax credit over the estimated lives of the related property.

Revenue Recognition—Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, and the price is fixed or determinable. In cases where significant obligations remain after delivery, revenue is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as the electric utility’s forward energy contracts and the energy services company’s swap transactions, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with SFAS No. 133 and Emerging Issues Task Force (EITF) Issues 02-3 and 03-11. Gains and losses on forward energy contracts subject to regulatory treatment are deferred and recognized on a net basis in revenue in the period realized.

For those operating businesses recognizing revenue when shipped, the operating businesses have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

Electric customers’ meters are read and bills are rendered monthly. Revenue is accrued for electricity consumed but not yet billed. Rate schedules applicable to substantially all customers include a fuel clause adjustment—under which the rates are adjusted to reflect changes in average cost of fuels and purchased power—and a surcharge for recovery of conservation-related expenses. Revenue is accrued for fuel and purchased power costs incurred in excess of amounts recovered in base rates but not yet billed through the fuel clause adjustment.

Revenues on wholesale electricity sales from Company-owned generating units are recognized when energy is delivered.

The Company’s unrealized gains and losses on forward energy contracts that do not meet the definition of capacity contracts are marked-to-market and reflected on a net basis in electric revenue on the Company’s consolidated statement of income. Under SFAS No. 149, the Company’s forward energy contracts that do not meet the definition of a capacity contract and are subject to unplanned netting do not qualify for the normal purchase and sales exception from mark-to-market accounting. The Company is required to mark-to-market these forward energy contracts and recognize changes in the fair value of these contracts as components of income over the life of the contracts.

Plastics operating revenues are recorded when the product is shipped.

Manufacturing operating revenues are recorded when products are shipped and on a percentage-of-completion basis for construction type contracts.

Health services operating revenues on major equipment and installation contracts are recorded when the equipment is delivered or when installation is completed and accepted. Amounts received in advance under customer service contracts are deferred and recognized on a straight-line basis over the contract period. Revenues generated in the imaging operations are recorded on a fee-per-scan basis when the scan is performed.

Food ingredient processing revenues related to dehydrated potato products are recorded when the product is shipped.

Other business operations operating revenues are recorded when services are rendered or products are shipped. In the case of construction contracts, the percentage-of-completion method is used.

Some of the operating businesses enter into fixed-price construction contracts. Revenues under these contracts are recognized on a percentage-of-completion basis. The method used to determine the progress of completion is based on the ratio of labor costs incurred to total estimated labor costs at the Company’s wind tower manufacturer, square footage completed to total bid square footage for certain floating dock projects and costs incurred to total estimated costs on all other construction projects. If a loss is indicated at a point in time during a contract, a projected loss for the entire contract is estimated and recognized. The following table summarizes costs incurred and billings and estimated earnings recognized on uncompleted contracts:

	December 31,			December 31,
(in thousands)	2005			2004
Costs incurred on uncompleted contracts	$	194,076		$	99,213
Less billings to date		(203,862	)		(96,413	)
Plus estimated earnings recognized		22,834			12,469
	$	13,048		$	15,269

The following costs and estimated earnings in excess of billings are included in the Company’s consolidated balance sheet. Billings in excess of costs and estimated earnings on uncompleted contracts are included in accounts payable.

	December 31,			December 31,
(in thousands)	2005			2004
Costs and estimated earnings in excess of billings on uncompleted contracts	$	21,542		$	18,145
Billings in excess of costs and estimated earnings on uncompleted contracts		(8,494	)		(2,876	)
	$	13,048		$	15,269

Foreign Currency Translation—The functional currency for the operations of the Canadian subsidiary of Idaho Pacific Holdings, Inc. (IPH) is the Canadian dollar. The translation of Canadian currency into U.S. dollars is performed for balance sheet accounts using exchange rates in effect at the balance sheet dates, except for the common equity accounts which are at historical rates, and for revenue and expense accounts using a weighted average exchange during the year. Gains or

losses resulting from the translation are included in Accumulated other comprehensive loss in the equity section of the Company’s consolidated balance sheet. All sales of the Canadian operations are in U.S. dollars so there are no foreign currency transaction gains or losses on receivables to be reported in the Company’s consolidated statements of income. The functional currency for the Canadian subsidiary of DMI Industries, Inc., formed in November 2005, is the U.S. dollar. Therefore, there are no foreign currency translation gains or losses related to this entity. However, this subsidiary may realize foreign currency transaction gains or losses on settlement of liabilities related to goods or services purchased in Canadian dollars. Foreign currency transaction gains or losses related to balance sheet adjustments of Canadian dollar liabilities to U.S. dollar equivalents or realized gains and losses on settlement of those liabilities will be included in other nonelectric expenses on the Company’s consolidated statements of income.

Pre-Production Costs—The Company incurs costs related to the design and development of molds, dies and tools as part of the manufacturing process. The Company accounts for these costs under EITF Issue 99-5, Accounting for Pre-production Costs Related to Long-Term Supply Arrangements. The Company capitalizes the costs related to the design and development of molds, dies and tools used to produce products under a long-term supply arrangement, some of which are owned by the Company. The balance of pre-production costs deferred on the balance sheet was $2,074,000 as of December 31, 2005 and $1,632,000 as of December 31, 2004. These costs are amortized over a three-year period and evaluated at least annually, or more often when events indicate an impairment could exist.

Shipping and Handling Costs—The Company includes revenues received for shipping and handling in operating revenues. Expenses paid for shipping and handling are recorded as part of cost of goods sold.

Stock-Based Compensation—As described in note 6, the Company has elected to follow the accounting provisions of Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, for stock-based compensation and to furnish the pro forma disclosures required under SFAS No. 123, Accounting for Stock-Based Compensation.

Had compensation costs for the stock options issued been determined based on estimated fair value at the award dates, as prescribed by SFAS No. 123, the Company’s net income for 2003 through 2005 would have decreased as presented in the table below. On January 1, 2006 the Company adopted SFAS No. 123(R), Share-Based Payment, which supersedes APB No. 25, on a modified prospective basis. Under SFAS No. 123(R), the estimated fair value of the options and other share-based payment plans, as determined on the award dates under SFAS No. 123, will be included in operating expense, net income and earnings per share beginning in 2006.

	2005			2004			2003
	(in thousands, except per share amounts)
Net income
As reported	$	62,551		$	42,195		$	39,656
Total stock-based employee compensation expense determined under fair value-based method for all awards net of related tax effects		(640	)		(1,087	)		(984	)
Pro forma	$	61,911		$	41,108		$	38,672
Basic earnings per share
As reported	$	2.12		$	1.59		$	1.52
Pro forma	$	2.09		$	1.55		$	1.48
Diluted earnings per share
As reported	$	2.11		$	1.58		$	1.51
Pro forma	$	2.08		$	1.54		$	1.47

Use of Estimates—The Company uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, unbilled electric revenues, valuations of forward energy contracts, unscheduled power exchanges and residual load adjustments related to purchase and sales transactions processed through the Midwest Independent Transmission System Operator (MISO) that are pending

settlement, service contract maintenance costs, percentage-of-completion and actuarially determined benefit costs. As better information becomes available (or actual amounts are known), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Adjustments and Reclassifications—Certain prior year amounts reported on the Company’s consolidated balance sheet have been reclassified to conform to 2005 presentation. On the Company’s consolidated balance sheets, regulatory assets and other deferred debits, previously disclosed on separate lines, have been combined on a single line. The December 31, 2004 consolidated balance sheet and consolidated income statements for 2004 and 2003 reflect the reclassification of certain assets, liabilities and operations of both St. George Steel Fabrication, Inc. (SGS) and Chassis Liner Corporation (CLC) from continuing operations to discontinued operations as a result of the sales of these businesses in 2005. Such reclassifications had no impact on total consolidated assets, net income or shareholders’ equity.

On the Company’s consolidated statement of cash flows for the year ended December 31, 2004 the change in the amount of checks issued in excess of cash, included in accounts payable on the Company’s consolidated balance sheet, was reclassified from change in payables and other current liabilities under cash flows from operating activities to change in checks written in excess of cash under cash flows from financing activities. This reclassification decreased cash flows from operating activities of continuing operations and increased cash flows from financing activities of continuing operations by $3,458,000 for the year ended December 31, 2004.

Cash Equivalents—The Company considers all highly liquid debt instruments purchased with maturity of 90 days or less to be cash equivalents.

Investments—The following table provides a breakdown of the Company’s investments at December 31, 2005 and 2004:

	December 31,		December 31,
(in thousands)	2005		2004
Cost method:
Acquisition escrow account	$	—	$	6,017
Economic development loan pools		742		879
Other		1,913		1,743
Equity method:
Affordable housing partnerships		2,980		3,802
Marketable securities classified as available-for-sale		3,067		2,009
Total investments	$	8,702	$	14,450

The Company has investments in eleven limited partnerships that invest in tax-credit-qualifying affordable-housing projects that provided tax credits of $1,324,000 in 2005, $1,418,000 in 2004 and $1,412,000 in 2003. The Company owns a majority interest in eight of the eleven limited partnerships with a total investment of $2,400,000. FASB Interpretation No.46, Consolidation of Variable Interest Entities, requires full consolidation of the majority-owned partnerships. However, the Company includes these entities on its consolidated financial statements on an equity method basis due to immateriality. Consolidating these entities would have represented less than 0.5% of the total assets of the Company.

The Company’s marketable securities classified as available-for-sale are held for insurance reserve purposes and are reflected at their market values on December 31, 2005, with $38,000 in unrealized losses included in Accumulated other comprehensive loss in the equity section of the Company’s December 31, 2005 consolidated balance sheet. See further discussion under note 12.

Inventories—The electric segment inventories are reported at average cost. All other segments’ inventories are stated at the lower of cost (first-in, first-out) or market.

Inventories consist of the following:

	December 31,		December 31,
(in thousands)	2005		2004
Finished goods	$	38,928	$	34,081
Work in process		7,146		3,733
Raw material, fuel and supplies		42,603		34,690
Total inventories	$	88,677	$	72,504

Goodwill and Intangible Assets—The Company accounts for goodwill and other intangible assets in accordance with the requirements of SFAS No. 142, Goodwill and Other Intangible Assets, which eliminates the requirement to amortize goodwill and indefinite-lived intangible assets, requiring instead those assets be measured for impairment at least annually and more often when events indicate an impairment could exist. Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.

The changes in the carrying amount of goodwill by segment are as follows:

			Adjustment to
	Balance		goodwill			Goodwill			Goodwill		Balance
	December 31,		acquired in			impairment			acquired		December 31,
(in thousands)	2004		2004			in 2005			in 2005		2005
Plastics	$	19,302	$	—		$	—		$	—	$	19,302
Manufacturing		9,680								6,018		15,698
Health services		24,582		(254	)							24,328
Food ingredient processing		23,087		1,153								24,240
Other business operations		15,545					(1,003	)				14,542
Total	$	92,196	$	899		$	(1,003	)	$	6,018	$	98,110

Intangible assets with finite lives are being amortized over average lives that vary from one to 25 years. The amortization expense for these intangible assets was $1,077,000 for 2005, $701,000 for 2004 and $478,000 for 2003. The estimated annual amortization expense for these intangible assets for the next five years is: $1,022,000 for 2006, $901,000 for 2007, $758,000 for 2008, $636,000 for 2009 and $507,000 for 2010.

In light of rising natural gas prices and greater volatility in natural gas futures prices, the Company reassessed the value of recorded goodwill of its energy services subsidiary as of September 30, 2005, in accordance with SFAS No. 142, Goodwill and Other Intangible Assets. As a result of this assessment, the Company determined the entire amount of goodwill related to this business was impaired and recorded a goodwill impairment loss of $1,003,000 in September 2005.

Total other intangibles as of December 31 are as follows:

	Gross carrying		Accumulated		Net carrying
	amount		amortization		amount
2005 (in thousands)
Amortized intangible assets:
Covenants not to compete	$	2,338	$	1,620	$	718
Customer relationships		10,575		583		9,992
Other intangible assets including contracts		2,785		1,680		1,105
Total	$	15,698	$	3,883	$	11,815
Nonamortized intangible assets:
Brand/trade name	$	9,345	$	—	$	9,345
2004 (in thousands)
Amortized intangible assets:
Covenants not to compete	$	1,966	$	1,334	$	632
Customer relationships		10,045		148		9,897
Other intangible assets including contracts		2,523		1,387		1,136
Total	$	14,534	$	2,869	$	11,665
Nonamortized intangible assets:
Brand/trade name	$	7,935	$	—	$	7,935

The Company periodically evaluates the recovery of intangible assets based on an analysis of undiscounted future cash flows. Evaluations of intangible assets, including goodwill, completed in December 2005 indicated none of the intangible assets reported on the Company’s consolidated balance sheet as of December 31, 2005 is impaired.

New Accounting Pronouncements

SFAS No. 151, Inventory Costs an amendment of ARB No. 43, Chapter 4, was issued in November 2004 to clarify that abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) should be recognized as current-period charges. This statement also requires that allocation of fixed production overheads to the costs of converting materials into finished products be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005 with earlier application permitted. The early application of this standard by the Company did not have a material effect on its consolidated net income, financial position or cash flows.

SFAS No. 123(R) (revised 2004), Share-Based Payment, issued in December 2004 is a revision of SFAS No. 123, Accounting for Stock-based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. The Company currently reports stock-based compensation under the requirements of APB Opinion No. 25 and furnishes related pro forma footnote information required under SFAS No. 123. Under SFAS No. 123(R), the Company will be required to record its stock-based compensation as an expense on its income statement over the period earned based on the fair value of the stock or options awarded on their grant date. SFAS No.123(R) becomes effective, and was adopted by the Company on a modified prospective basis, on January 1, 2006. The application of SFAS No. 123(R) reporting requirements will result in recording compensation expense of approximately $160,000, net-of-tax, in 2006 for its currently outstanding non-vested stock options. Additionally, the application of SFAS No. 123(R) reporting requirements will result in recording compensation expense of approximately $240,000, net-of-tax, in 2006 for the 15% discount offered under the Company’s Employee Stock Purchase Program (ESPP), if shareholders approve the Board of Directors’ authorization of additional             shares for the ESPP. See note 6 for additional information.

FASB Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations, is an interpretation of SFAS No. 143 on accounting for obligations associated with the retirement of tangible, long-lived assets. The revised guidance on conditional obligations is effective for fiscal years ending after

December 15, 2005. The interpretation provides clarification and further guidance about when sufficient information exists to reasonably estimate the fair value of legal obligations in circumstances where uncertainty exists about the timing and (or) methods of settlement of a conditional asset retirement obligation. The Company evaluated its legal obligations in light of the additional guidance provided by this interpretation and determined that its previously recognized obligations did not change under this interpretation. However, the Company did determine that its transmission and distribution lines rights-of-way, including those with indeterminate lives, are not subject to the provisions of SFAS No. 143 because they are intangible assets. The Company also determined that it has no legal retirement obligations associated with structures using those rights-of-way.

SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, was issued in December 2004. This statement addresses the measurement of exchanges of nonmonetary assets. It eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29, Accounting for Nonmonetary Transactions, and replaces it with an exception for exchanges that do not have commercial substance. This statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this statement shall be effective and applied prospectively for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005 with earlier application permitted. The early application of this standard by the Company did not have a material effect on its consolidated net income, financial position or cash flows.

SFAS No. 154, Accounting for Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3, was issued in May 2005. This statement provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. This statement also provides guidance for determining whether retrospective application of a change in accounting principle is impracticable and for reporting a change when retrospective application is impracticable. This statement shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, with early adoption permitted. The Company does not expect the application of the requirements of SFAS No. 154 to have a material effect on the Company’s consolidated net income, financial position or cash flows.

2. Business Combinations, Dispositions and Segment Information

On January 3, 2005 the Company’s wholly-owned subsidiary, BTD Manufacturing, Inc. (BTD), acquired the assets of Performance Tool & Die, Inc. (Performance Tool) of Lakeville, Minnesota, for $4.1 million in cash. Performance Tool specializes in manufacturing mid to large progressive dies for customers throughout the Midwest, East and West Coasts, and the southern United States. Performance Tool’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 and Performance Tool.

Also, on January 3, 2005 the Company’s wholly-owned subsidiary, ShoreMaster, Inc. (ShoreMaster), acquired the common stock of Shoreline Industries, Inc. (Shoreline), 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.

Below are condensed balance sheets, at the date of the business combinations, disclosing the allocation of the purchase price assigned to each major asset and liability category of the acquired companies.

	Performance		Shoreline		Southeast
(in thousands)	Tool		Industries		Floating Docks
Assets
Current assets	$	748	$	464	$	2,437
Plant		1,396		260		415
Deferred income taxes		22		—		—
Goodwill		1,772		1,442		2,804
Other intangible assets		800		557		1,150
Total assets	$	4,738	$	2,723	$	6,806
Liabilities
Current liabilities	$	324	$	86	$	318
Deferred revenue		—		—		2,520
Deferred income taxes		—		235		—
Long-term debt		298		—		—
Total liabilities	$	622	$	321	$	2,838
Cash paid	$	4,116	$	2,402	$	3,968

Goodwill and other intangible assets related to the Performance Tool acquisition are deductible for income tax purposes over 15 years. Other intangible assets related to the Performance Tool acquisition includes $239,000 for a nonamortizable trade name and $561,000 in other intangible assets being amortized over 3 to 15 years for book purposes. Goodwill and other intangible assets related to the Shoreline acquisition are not deductible for income tax purposes, except for a $171,000 noncompete agreement being amortized over 15 years for income tax purposes. Other intangible assets related to the Shoreline acquisition includes $149,000 for a nonamortizable brand name and $408,000 in other intangible assets being amortized over 5 to 20 years for book purposes. Goodwill and other intangible assets related to the Southeast Floating Docks acquisition are deductible for income tax purposes over 15 years. Other intangible assets related to the Southeast Floating Docks acquisition includes $1,000,000 for a nonamortizable brand name.

On August 18, 2004 the Company acquired all of the outstanding common stock of Idaho Pacific Holdings, Inc., (IPH) of Ririe, Idaho, a leading processor of dehydrated potato products in North America, for $68.2 million in cash. An additional $6.0 million in cash was placed in escrow to pay off earn-out contingencies if IPH achieved certain financial targets for the period from August 1, 2004 through July 31, 2005. The financial targets were not achieved and the $6.0 million of funds held in escrow were returned to the Company in the third quarter of 2005. The results of operations of IPH have been included in the Company’s consolidated results of operations since the date of acquisition and are included in the food ingredient processing segment. This acquisition added a new platform to the Company’s diversified portfolio of businesses. IPH is headquartered in Ririe, Idaho, where its largest processing facility is located. It also has potato dehydration plants in Souris, Prince Edward Island, Canada, and Center, Colorado. IPH supplies products for use in foods such as mashed potatoes, snacks and baked goods. Its customers include many of the largest domestic and international food manufacturers in the snack food, foodservice and baking industries. IPH exports potato products to Europe, the Middle East, the Pacific Rim and Central America. IPH had revenues of $43.5 million for its fiscal year ended July 31, 2004.

Below is a condensed balance sheet of IPH disclosing the final allocation of the purchase price assigned to each major asset and liability category.

(in thousands)	IPH
Assets
Current assets	$	17,740
Plant		35,296
Goodwill		24,240
Other intangible assets		13,200
Total assets	$	90,476
Liabilities
Current liabilities	$	5,893
Deferred income taxes		12,408
Long-term debt		2,140
Class B common stock options		1,832
Total liabilities	$	22,273
Cash paid	$	68,203

Goodwill and other intangible assets related to the IPH acquisition are not deductible for income tax purposes. Other intangible assets related to the IPH acquisition include $10.0 million for customer relationships being amortized over 25 years and a $3.2 million nonamortizable trade name.

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

In 2003, the Company also acquired Topline Medical, Inc., and North Star Medical Systems, Inc. The aggregate price paid for these companies was $1.9 million in cash. These acquisitions allowed the health services segment to increase sales opportunities with an expanded line of products.

Below is a condensed balance sheet disclosing the final allocation of the purchase price assigned to each major asset and liability category for the companies acquired in 2003.

(in thousands)	Foley		Others
Assets
Current assets	$	9,847	$	675
Plant		3,793		45
Goodwill		7,319		1,924
Other intangible assets		1,653		102
Total assets	$	22,612	$	2,746
Liabilities
Current liabilities	$	8,618	$	669
Long-term debt		—		136
Other long-term liabilities		1,712		—
Total liabilities	$	10,330	$	805
Cash paid	$	12,282	$	1,941

Goodwill related to the Foley acquisition is not deductible for income tax purposes. The goodwill related to the other 2003 acquisitions is deductible for income tax purposes over 15 years. Other intangible assets related to the Foley acquisition include a $1.1 million nonamortizable trade name and $553,000 in intangible assets being amortized over five years. Other intangible assets

related to the other acquisitions are being amortized over four years.

All of the acquisitions described above were accounted for using the purchase method of accounting. The pro forma effect of these acquisitions on 2005, 2004 and 2003 revenues, net income or earnings per share was not significant.

Segment Information—The accounting policies of the segments are described under note 1 – Summary of Significant Accounting Policies. The Company’s businesses have been classified into six segments based on products and services and reach customers in all 50 states and international markets. The six segments are: electric, plastics, manufacturing, health services, food ingredient processing and other business operations.

Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota under the name Otter Tail Power Company. Electric utility operations have been the Company’s primary business since incorporation.

Plastics 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 are located primarily in the Upper Midwest and Missouri.

Health services consists of businesses involved in the sale of diagnostic medical equipment, patient monitoring equipment and related supplies and accessories. These businesses also provide service maintenance, diagnostic imaging, positron emission tomography and nuclear medicine imaging, portable X-ray imaging and rental of diagnostic medical imaging equipment to various medical institutions located throughout the United States.

Food ingredient processing consists of IPH, which owns and operates potato dehydration plants in Ririe, Idaho; Center, Colorado and Souris, Prince Edward Island, Canada, producing dehydrated potato products that are sold in the United States, Canada, Europe, the Middle East, the Pacific Rim and Central America.

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; and 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 six 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 a wholly-owned subsidiary of the Company.

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information on continuing operations for the business segments for 2005, 2004 and 2003 is presented in the following table.

	2005			2004			2003
	(in thousands)
Operating revenue
Electric	$	312,985		$	266,385		$	267,494
Plastics		158,548			115,426			86,009
Manufacturing		244,311			201,615			157,401
Health services		123,991			114,318			100,912
Food ingredient processing		38,501			14,023			—
Other business operations		171,939			148,328			114,726
Intersegment eliminations		(3,867	)		(2,733	)		(2,254	)
Total	$	1,046,408		$	857,362		$	724,288
Depreciation and amortization
Electric	$	24,397		$	24,236		$	26,008
Plastics		2,511			2,297			2,126
Manufacturing		9,447			7,828			6,882
Health services		4,038			5,047			5,137
Food ingredient processing		3,399			1,118			—
Other business operations		2,666			2,945			2,841
Total	$	46,458		$	43,471		$	42,994
Income before income taxes
Electric	$	55,984		$	45,234		$	48,689
Plastics		22,803			9,453			3,341
Manufacturing		12,242			12,543			6,904
Health services		6,875			5,075			4,197
Food ingredient processing		1,482			618			—
Other business operations		(18,564	)		(14,844	)		(10,744	)
Total	$	80,822		$	58,079		$	52,387
Earnings available for common shares
Electric	$	36,566		$	30,799		$	33,411
Plastics		13,936			5,657			2,019
Manufacturing		7,589			7,563			4,495
Health services		4,007			2,951			2,464
Food ingredient processing		329			351			—
Other business operations		(10,307	)		(7,425	)		(4,899	)
Total	$	52,120		$	39,896		$	37,490
Capital expenditures
Electric	$	30,479		$	25,368		$	28,177
Plastics		3,636			2,544			3,984
Manufacturing		16,112			13,163			9,592
Health services		3,095			3,919			5,427
Food ingredient processing		2,952			3,528			—
Other business operations		3,695			962			1,603
Total	$	59,969		$	49,484		$	48,783
Identifiable assets
Electric	$	654,175		$	634,433		$	609,190
Plastics		76,573			67,574			58,538
Manufacturing		177,969			150,800			125,877
Health services		67,066			66,506			67,587
Food ingredient processing		96,023			92,392			—
Other business operations		107,373			91,506			95,350
Discontinued operations		2,317			30,937			29,881
Total	$	1,181,496		$	1,134,148		$	986,423

No single external customer accounts for 10% or more of the Company’s revenues. Substantially all of the Company’s long-lived assets are within the United States except for a food ingredient processing dehydration plant in Souris, Prince Edward Island, Canada and a wind tower manufacturing plant in Fort Erie, Ontario, Canada.

Percent of sales revenue by country for the year ended December 31:

	2005			2004			2003
United States of America		97.9	%		97.1	%		100.0	%
Canada		1.0	%		2.1	%		—
All other countries		1.1	%		0.8	%		—

3. Rate Matters

On December 29, 2000 the North Dakota Public Service Commission (NDPSC) approved a performance-based ratemaking 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 plan was in place through 2005. This plan provided the opportunity for the electric utility to raise its allowed rate of return and share income with customers when earnings exceed the allowed return. The electric utility’s 2005 rate of return is expected to be within the allowable range defined in the plan. The electric utility’s 2004 and 2003 rates of return were within the allowable range defined in the plan. The performance-based ratemaking plan expired on December 31, 2005. While the electric utility has applied to the NDPSC for a three year extension with certain modifications, the NDPSC has taken no action on the application.

The Energy Policy Act of 2005 (the 2005 Energy Act) was signed into law in August 2005. The 2005 Energy Act is comprehensive legislation that will substantially affect the regulation of energy companies. 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:

• 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.

• 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.

• The Price Anderson Amendments Act of 1988, which provides the framework for nuclear liability protection, will be extended by 20 years to 2025.

• 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 Otter Tail Power Company was informed that the Division of Operation Audits of the OMOI would be commencing an audit of Otter Tail Power Company. 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. FERC has been conducting audits of this nature since Order No. 889 was issued and more since the implementation of Order No. 2004 (FERC’s Standards of Conduct Order). The audit is expected to take approximately six months to complete. The Company believes it is in compliance with applicable FERC rules, regulations and tariff requirements related to the audit. Given the preliminary nature of this audit, the Company is not able to determine whether the audit will result in any material changes to the Company’s operations or have any material effect on the Company’s consolidated net income, financial position or cash flows.

On November 30, 2004, Otter Tail Power Company filed a report with the Minnesota Public Utilities Commission (MPUC) responding to claims of allegedly improper regulatory filings brought to the attention of the Company by certain

individuals. In 2005, the Energy Division of the Minnesota Department of Commerce, 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 is expected to be scheduled in March 2006. The Company cannot predict whether the results of the hearing will have any impact on the Company’s consolidated net income, financial position or cash flows.

In December 2005, the MPUC issued an order denying the 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 electric utility to reflect the refund obligation. On February 9, 2006 the MPUC reconsidered its December 2005 order. On reconsideration, the MPUC 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 possible recovery through base rates in the electric utility’s next general rate case. The MPUC’s final written order of this action is pending. When the final order is issued, the electric utility will recognize the $1.9 million in revenue and reverse the refund payable.

4. Regulatory Assets and Liabilities

The following table indicates the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

	December 31,		December 31,
(in thousands)	2005		2004
Regulatory assets:
Deferred income taxes	$	16,724	$	14,526
Reacquisition premiums		2,995		3,424
Deferred conservation program costs		1,064		1,203
Plant acquisition costs		196		240
Deferred marked-to-market losses		1,423		331
Accrued cost-of-energy revenue		10,400		3,348
Accumulated ARO accretion/depreciation adjustment		209		114
Total regulatory assets	$	33,011	$	23,186
Regulatory liabilities:
Accumulated reserve for estimated removal costs	$	52,582	$	49,823
Deferred income taxes		5,961		6,727
Deferred marked-to-market gains		2,925		197
Gain on sale of division office building		156		162
Total regulatory liabilities	$	61,624	$	56,909
Net regulatory liability position	$	28,613	$	33,723

The regulatory assets and liabilities related to deferred income taxes result from changes in statutory tax rates accounted for in accordance with SFAS No. 109, Accounting for Income Taxes. Reacquisition premiums included in Unamortized debt expense and reacquisition premiums are being recovered from electric utility customers over the remaining original lives of the reacquired debt issues, the longest of which is 16.6 years. Deferred conservation program costs represent mandated conservation expenditures recoverable through retail electric rates over the next 1.5 years. Plant acquisition costs will be amortized over the next 4.4 years. Accrued cost-of-energy revenue included in Accrued utility revenues will be recovered over the next nine months. All deferred marked-to-market gains and losses are related to forward purchases and sales of energy scheduled for delivery prior to September 2006. The accumulated reserve for estimated removal costs is reduced for actual removal costs incurred. The remaining regulatory assets and liabilities are being recovered from, or will be paid to, electric customers over the next 30 years.

If for any reason, the Company’s regulated businesses cease to meet the criteria for application of SFAS No. 71 for all or part of their operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an extraordinary expense or income item in the period in which the application of SFAS No. 71 ceases.

5. Forward Energy Contracts Classified as Derivatives

Electricity Contracts

With the issuance of SFAS No. 149 in 2003, all of the electric utility’s wholesale purchases and sales of energy under forward contracts that do not meet the definition of capacity contracts are considered derivatives subject to mark-to-market accounting. The electric utility’s objective in entering into forward contracts for the purchase and sale of energy is to optimize the use of its generating and transmission facilities and leverage its knowledge of wholesale energy markets in the region to maximize financial returns for the benefit of both its customers and shareholders. The electric utility’s intent in entering into certain of these contracts is to settle them through the physical delivery of energy when physically possible and economically feasible. The electric utility also enters into certain contracts for trading purposes with the intent to profit from fluctuations in market prices through the timing of purchases and sales.

Electric revenues include $46,397,000 in 2005, $27,228,000 in 2004 and $29,702,000 in 2003 related to wholesale electric sales and net unrealized derivative gains on forward energy contracts and, in 2005, sales of financial transmission rights and daily settlements of virtual transactions in the MISO market, broken down as follows for the years ended December 31:

(in thousands)	2005			2004			2003
Wholesale sales — company–owned generation	$	24,799		$	17,970		$	18,600
Revenue from settled contracts at market prices		474,882			134,715			121,303
Market cost of settled contracts		(457,728	)		(128,685	)		(114,259	)
Net margins on settled contracts at market		17,154			6,030			7,044
Marked-to-market gains on settled contracts		11,118			12,663			2,978
Marked-to-market losses on settled contracts		(9,590	)		(9,736	)		(977	)
Net marked-to-market gain on settled contracts		1,528			2,927			2,001
Unrealized marked-to-market gains on open contracts		5,678			514			6,338
Unrealized marked-to-market losses on open contracts		(2,762	)		(213	)		(4,281	)
Net unrealized marked-to-market gain on open contracts		2,916			301			2,057
Wholesale electric revenue	$	46,397		$	27,228		$	29,702

The following tables show the effect of marking-to-market forward contracts for the purchase and sale of energy on the Company’s consolidated balance sheets:

	December 31,			December 31,
(in thousands)	2005			2004
Current asset – marked-to-market gain	$	8,603		$	711
Regulatory asset – deferred marked-to-market loss		1,423			331
Total assets		10,026			1,042
Current liability – marked-to-market loss		(4,185	)		(544	)
Regulatory liability – deferred marked-to-market gain		(2,925	)		(197	)
Total liabilities		(7,110	)		(741	)
Net fair value of marked-to-market energy contracts	$	2,916		$	301

	Year ended
	December 31,
(in thousands)	2005
Fair value at beginning of year	$	301
Amount realized on contracts entered into in 2004 and settled in 2005		(322	)
Changes in fair value of contracts entered into in 2004		21
Net fair value of contracts entered into in 2004 at year end 2005		—
Changes in fair value of contracts entered into in 2005		2,916
Net fair value at end of year	$	2,916

The $2,916,000 in recognized but unrealized net gains on the forward energy purchases and sales marked-to-market as of December 31, 2005 is expected to be realized on physical settlement or settled by an offsetting agreement with the counterparty to the original contract as scheduled over the following quarters in the amounts listed:

	1st Quarter		2nd Quarter		3rd Quarter
(in thousands)	2006		2006		2006		Total
Net gain	$	2,281	$	527	$	108	$	2,916

Of the forward energy contracts that are marked-to-market as of December 31 2005, 91% of the forward energy purchases have offsetting sales in terms of volumes and delivery periods. The amount of net unrealized marked-to-market losses recognized on forward energy purchases that are not offset by forward energy sales is $269,000.

Natural Gas Contracts

The Company’s energy services subsidiary markets natural gas to approximately 160 retail customers. Some of these customers are served under fixed-price contracts. These contracts call for the physical delivery of natural gas and are considered executory contracts for accounting purposes. Current accounting guidance requires losses on firmly committed executory contracts to be recognized when realized.

The Company’s energy services subsidiary first entered into over-the-counter natural gas forward swap transactions that qualify as derivatives subject to mark-to-market accounting under SFAS No. 133 in 2004. Although the energy services subsidiary manages its risk by balancing its position in these transactions relative to its market position in the contracts entered into for physical delivery, these swap transactions do not qualify for the normal purchases and sales exception nor do they qualify for hedge accounting treatment under SFAS No. 133. These contracts are held for trading purposes with both realized and unrealized net gains and losses reflected in revenue on the Company’s consolidated statements of income for the years ended December 31, 2005 and 2004 in accordance with the guidance provided in EITF 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. The Company’s intent in entering into these forward natural gas swap transactions is to make a profit on the change in prices of natural gas contracted for future delivery.

The following table provides a breakdown of the energy services subsidiary’s natural gas swap transactions trading activity in 2005 and 2004:

(in thousands)	2005			2004
Gains on settled contracts	$	17,685		$	780
Losses on settled contracts		(18,161	)		(747	)
Net (loss) gain on settled contracts		(476	)		33
Unrealized gains on open contracts		825			1,834
Unrealized losses on open contracts		(851	)		(1,700	)
Net unrealized (loss) gain on open contracts		(26	)		134
Net revenue recognized	$	(502	)	$	167

The following tables show the effect of marking-to-market the energy services subsidiary’s forward natural gas swap transactions on the consolidated balance sheets:

	December 31,			December 31,
(in thousands)	2005			2004
Current asset — marked-to-market gain	$	825		$	1,834
Current liability — marked-to-market loss		(851	)		(1,700	)
Net fair value of marked-to-market gas contracts	$	(26	)	$	134

	Year ended
	December 31,
(in thousands)	2005
Fair value at beginning of year	$	134
Amount realized on contracts entered into in 2004 and settled in 2005		(134	)
Changes in fair value of contracts entered into in 2004		—
Net fair value of contracts entered into in 2004 at year end 2005		—
Changes in fair value of contracts entered into in 2005		(26	)
Net fair value at end of year	$	(26	)

The $26,000 in recognized but unrealized net loss on these forward natural gas swap transactions marked-to-market on December 31, 2005 is expected to be realized on settlement in the first quarter of 2006.

6. Common Shares and Earnings Per Share

New Issuances— In January 2005, 175,000 common shares were issued as a result of the underwriters exercising a portion of their over-allotment option in connection with the Company’s December 2004 public offering. The proceeds to the Company of $24.50 per share were used to pay down debt borrowed to finance the acquisition of IPH. Also in 2005, the Company issued 258,096 common shares as a result of stock option exercises, 20,700 restricted common shares for officers’ and directors’ compensation and 2,415 common shares as directors’ compensation.

In 2005, the Company retired 14,547 common shares for tax withholding purposes in connection with the vesting of restricted common shares, 240 restricted common shares that were forfeited prior to vesting, and 17,120 common shares related to the return of stock to the Company that was held in escrow for performance contingencies that were not achieved in a health services acquisition.

Stock Incentive Plan—Under the 1999 Stock Incentive Plan (Incentive Plan) a total of 2,600,000 common shares were authorized for granting stock awards. The Incentive Plan provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, and other stock and stock-based awards. The Company’s Board of Directors authorized an additional 1,000,000 common shares for the Incentive Plan and extended the term of the Incentive Plan from December 13, 2008 to December 13, 2013 subject to shareholder approval in April 2006.

The exercise price of the stock options is equal to the fair market value per share at the date of the grant. Options granted to non-employee directors are exercisable immediately and all other options granted prior to 2004 vest over a four-year period. Stock options granted in 2004 and 2005 vested six months from the grant date. Options expire ten years after the date of the grant. Restricted stock awards outstanding as of December 31, 2005 vest ratably over a four-year period. The Company accounted for the Incentive Plan under APB No. 25 through December 31, 2005, but adopted the accounting requirements of SFAS No. 123(R) for the Incentive Plan on a modified prospective basis on January 1, 2006. See New Accounting Pronouncements under note 1.

Presented below is a summary of the stock options activity:

Stock Option Activity	2005				2004				2003
			Average				Average				Average
			exercise				exercise				exercise
	Options		price		Options		price		Options		price
Outstanding, beginning of year		1,508,277	$	25.35		1,531,125	$	25.16		1,360,721	$	24.68
Granted		74,900		24.93		72,400		26.50		222,750		27.24
Exercised		257,948		22.90		51,468		19.83		47,700		20.21
Forfeited		88,065		28.79		43,780		27.37		4,646		23.09
Outstanding, year end		1,237,164		25.58		1,508,277		25.35		1,531,125		25.16
Exercisable, year end		1,095,272		25.16		1,111,681		24.27		791,661		22.97
Fair value of options granted during year	$	4.76			$	5.27			$	5.42

The fair values of the options granted were estimated using the Black-Scholes option-pricing model under the following assumptions:

	2005			2004			2003
Risk-free interest rate		4.3	%		3.9	%		3.7	%
Expected lives	7 years			7 years			7 years
Expected volatility		25.4	%		25.7	%		26.3	%
Dividend yield		4.4	%		4.0	%		4.0	%

The following table summarizes information about options outstanding as of December 31, 2005:

	Options outstanding						Options exercisable
			Weighted-
			average		Weighted-				Weighted-
	Outstanding		remaining		average		Exercisable		average
Range of	as of		contractual		exercise		as of		exercise
exercise prices	12/31/05		life (yrs)		price		12/31/05		price
$18.80-$21.94		308,890		3.7	$	19.48		308,890	$	19.48
$21.95-$25.07		66,400		9.3	$	24.93		66,400	$	24.93
$25.08-$28.21		624,250		6.1	$	26.54		536,750	$	26.42
$28.22-$31.34		237,624		6.1	$	31.21		183,232	$	31.17

See note 1 for pro forma stock option information.

In addition to the stock options granted, 20,700, 21,340 and 90,900 shares of restricted stock were granted during 2005, 2004 and 2003, respectively. The total compensation cost recognized in income for the restricted stock awards was $1,379,000 in 2005, $1,302,000 in 2004 and $1,110,000 in 2003.

The Company’s Board of Directors has approved performance award agreements under the Incentive Plan for the Company’s executive officers. Under these agreements, the officers could be awarded common shares based on the Company’s total shareholder return relative to that of its peer group of companies in the Edison Electric Institute (EEI) Index over a three-year period beginning on January 1, of the year the awards are granted. The number of shares earned, if any, will be awarded and issued at the end of each three-year performance measurement period. The participants have no voting or dividend rights under these award agreements until the shares are issued at the end of the performance measurement period. A summary of activity under the performance award agreements as of and for the years ended December 31, 2005 and 2004 is as follows:

	Maximum		Amount of shares		Amount of
	shares		expected to be awarded		expense during
Performance	subject		based on current		the years ended
Period	to award		stock performance		December 31,
					2005		2004
2005-2007		75,150		50,872	$	490,000		—
2004-2006		70,500		23,500	$	453,000		—

Employee Stock Purchase Plan—The 1999 Employee Stock Purchase Plan (Purchase Plan) allows eligible employees to purchase the Company’s common shares at 85% of the lower market price at either the beginning or the end of each six-month purchase period. Starting in 2006, the purchase price of common shares under the

Purchase Plan will be 85% of the market price at the end of each six-month purchase period. Of the 400,000 common shares authorized for purchase under the Purchase Plan, 2,961 were still available for purchase as of December 31, 2005. To provide shares for the Purchase Plan, 69,401 common shares were purchased in the open market in 2005, 66,958 common shares were issued in 2004 and 66,724 common shares were purchased in the open market in 2003. The Company’s Board of Directors authorized an additional 500,000 common shares for the Purchase Plan subject to shareholder approval in April 2006.

Dividend Reinvestment and Share Purchase Plan—On August 30, 1996 the Company filed a shelf registration statement with the Securities and Exchange Commission (SEC) for the issuance of up to 2,000,000 common shares pursuant to the Company’s Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by shareholders or customers who participate in the Plan to be either new issue common shares or common shares purchased in the open market. From June 1999 through December 2003, common shares needed for the Plan were purchased in the open market. From January through October 2004 new shares were issued for this Plan. Starting in November 2004 the Company began purchasing common shares in the open market. Through December 31, 2005, 944,507 common shares had been issued to meet the requirements of the Plan.

Shareholder Rights Plan—On January 27, 1997 the Company’s Board of Directors declared a dividend of one preferred share purchase right (Right) for each outstanding common share held of record as of February 15, 1997. One Right was also issued with respect to each common share issued after February 15, 1997. Each Right entitles the holder to purchase from the Company one one-hundredth of a share of newly created Series A Junior Participating Preferred Stock at a price of $70, subject to certain adjustments. The Rights are exercisable when, and are not transferable apart from the Company’s common shares until, a person or group has acquired 15% or more, or commenced a tender or exchange offer for 15% or more, of the Company’s common shares. If the specified percentage of the Company’s common shares is acquired, each Right will entitle the holder (other than the acquiring person or group) to receive, on exercise, common shares of either the Company or the acquiring company having value equal to two times the exercise price of the Right. The Rights are redeemable by the Company’s Board of Directors in certain circumstances and expire on January 27, 2007.

Earnings Per Share—Basic earnings per common share are calculated by dividing earnings available for common shares by the average number of common shares outstanding during the period. Diluted earnings per common share are calculated by adjusting outstanding shares, assuming conversion of all potentially dilutive stock options. Stock options with exercise prices greater than the market price are excluded from the calculation of diluted earnings per common share.

7. Retained Earnings Restriction

The Company’s Articles of Incorporation, as amended, contain provisions that limit the amount of dividends that may be paid to common shareholders by the amount of any declared but unpaid dividends to holders of the Company’s cumulative preferred shares. Under these provisions none of the Company’s retained earnings were restricted at December 31, 2005.

8. Commitments and Contingencies

At December 31, 2005 the electric utility had commitments under contracts in connection with construction programs aggregating approximately $4,417,000. For capacity and energy requirements, the electric utility has agreements extending through 2010 at annual costs of approximately $16,957,000 in 2006, $16,359,000 in 2007, $16,339,000 in 2008, $16,358,000 in 2009 and $7,954,000 in 2010.

The electric utility has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. These contracts expire in 2007 and 2016. In total, the electric utility is committed to the minimum purchase of approximately $83,981,000 or to make payments in lieu thereof, under these contracts. The fuel clause adjustment mechanism lessens the risk of loss from market price changes because it provides for recovery of most fuel costs.

The Company’s wind tower manufacturer has commitments totaling $37,909,000 for the purchase of steel plates in 2006 to be used in the construction of towers that are scheduled for delivery in 2006 and 2007.

The amounts of future operating lease payments are as follows:

	Electric		Nonelectric		Total
			(in thousands)
2006	$	1,980	$	35,301	$	37,281
2007		1,699		30,172		31,871
2008		1,243		25,688		26,931
2009		1,243		22,374		23,617
2010		1,243		12,125		13,368
Later years		497		2,705		3,202
Total	$	7,905	$	128,365	$	136,270

The electric future operating lease payments are primarily related to coal rail-car leases. The nonelectric future operating lease payments are primarily related to medical imaging equipment. Rent expense from continuing operations was $37,798,000, $28,061,000 and $25,205,000, for 2005, 2004 and 2003, respectively.

The Company occasionally is a party to litigation arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of December 31, 2005 will not be material.

9. Short-Term and Long-Term Borrowings

Short-Term Debt— As of December 31, 2005 the Company had $16 million in short-term debt outstanding at an interest rate of 4.8%. As of December 31, 2004 the Company had $39,950,000 in short-term debt outstanding, of which $35,000,000 was borrowed against the Company’s line of credit and $4,950,000 was the remaining unpaid balance on a bridge loan used to finance the 2004 acquisition of IPH. As of December 31, 2004 the composite interest rate on the line borrowings was 2.8% and the interest rate on the bridge loan was 3.0%. The average interest rate paid on short-term debt was 3.7% in 2005 and 2.2% in 2004.

In August 2004, the Company borrowed $76.0 million of unsecured and unsubordinated debt from UBS Loan Finance LLC as a bridge loan to finance its acquisition of IPH. The Company repaid $71,050,000 of the $76.0 million loan in December 2004 with net proceeds from the issuance of 2.9 million shares of common stock in a public offering. The remaining unpaid balance of $4,950,000, outstanding on December 31, 2004, was repaid in January 2005 from the proceeds of 175,000 shares of common stock issued as a result of the underwriters exercising a portion of their over-allotment in connection with the public offering and by borrowing from the Company’s line of credit. The interest rate paid on the outstanding balance on the bridge loan was 3.0%.

On April 27, 2005 the Company renewed its line of credit with U.S. Bank National Association, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, and Bank Hapoalim B.M., and increased the amount available under the line from $70 million to $100 million. The renewed agreement expires on April 26, 2006. The terms of the renewed line of credit are essentially the same as those in place prior to the renewal. However, outstanding letters of credit issued by the Company can reduce the amount available for borrowing under the line by up to $20 million. Borrowings under the line of credit bear interest at LIBOR plus 0.6%, subject to adjustment based on the ratings of the Company’s senior unsecured debt. This line is an unsecured revolving credit facility available to support borrowings of our nonelectric operations. We anticipate that the electric utility’s cash requirements through April 2006 will be provided for by cash flows from electric utility operations. As of December 31, 2005, $16.0 million of the $100 million line of credit in place at that date was in use and $12.0 million was restricted from use to cover outstanding letters of credit. The Company does not anticipate any difficulties in renewing this line of credit.

The interest rate under the line of credit is subject to adjustment in the event of a change in ratings on the Company’s senior unsecured debt, up to LIBOR plus 0.8% if the ratings on the Company’s senior unsecured debt fall to BBB+ or below (Standard & Poor’s) or Baa1 or below (Moody’s). On August 26, 2005 Moody’s Investors Service lowered its ratings of the Company’s senior unsecured debt from A2 to A3 and changed its outlook from negative to stable. On December 22, 2005 Standard & Poor’s Rating Services changed its outlook on the Company’s senior unsecured debt from negative to stable. No changes were made to its ratings of

the Company’s senior unsecured debt which has a rating of BBB+. These rating changes did not affect the interest rate on the line of credit which remained at LIBOR plus 0.6%.

The Company’s bank line of credit is a key source of operating capital and can provide interim financing of working capital and other capital requirements, if needed. The Company’s obligations under this line of credit are guaranteed by a 100%-owned subsidiary of the Company that owns substantially all of the Company’s nonelectric companies.

Long-Term Debt—The Company has the ability to issue up to $256 million of common shares, cumulative preferred shares, debt and certain other securities from time to time under its universal shelf registration statement filed with the Securities and Exchange Commission on June 4, 2004 and declared effective on August 30, 2004. The Company issued no long-term debt under its universal shelf registration in 2005 or 2004.

On September 24, 2003 the Company borrowed $16.3 million under a loan agreement with Lombard US Equipment Finance Corporation in the form of an unsecured note. The terms of the note require quarterly principal payments in the amount of $582,143 commencing in January 2004 with a final installment due on October 2, 2006, the stated maturity date of the note. The term of the note can be extended for additional one-year periods following the stated maturity date through October 1, 2010. The note bears interest at a variable rate of three-month LIBOR plus 1.43% on the unpaid principal balance with interest payments due quarterly. The covenants associated with the note are consistent with existing credit facilities. There are no rating triggers associated with this note.

On November 3, 2004 a Second Amendment to the Note Purchase Agreement dated as of December 31, 2001 for the $90 million 6.63% senior notes due December 1, 2011 between Otter Tail Corporation and the holders of the notes was signed and made effective as of October 1, 2004. This amendment eliminated the provision that would require repayment of the $90 million senior notes with a make-whole premium if the Company’s senior unsecured debt is rated below Baa3 (Moody’s) or BBB- (Standard & Poor’s). The amendment resulted in no changes to interest rates and no material changes to other terms of the agreement. The Company’s obligations under the 6.63% senior notes are guaranteed by a 100%-owned subsidiary of the Company that owns substantially all of the Company’s nonelectric companies.

The Company’s Grant County and Mercer County pollution control refunding revenue bonds require the Company grant to Ambac Assurance Corporation, under a financial guaranty insurance policy relating to the bonds, a security interest in the assets of the electric utility if the rating on the Company’s senior unsecured debt is downgraded to Baa2 or below (Moody’s) or BBB or below (Standard & Poor’s).

The aggregate amounts of maturities on bonds outstanding and other long-term obligations at December 31, 2005 for each of the next five years are $3,340,000 for 2006, $54,896,000 for 2007, $3,006,000 for 2008, $2,904,000 for 2009 and $2,568,000 for 2010.

Covenants—The Company’s line of credit, its $90 million 6.63% senior notes due 2011 and Lombard US Equipment Finance note contain covenants that require the Company to maintain a debt-to-total capitalization ratio not in excess of 60% and an interest and dividend coverage ratio of at least 1.5 to 1. The 6.63% senior notes also require that priority debt not be in excess of 20% of total capitalization. The Company was in compliance with all of the covenants under these financing agreements as of December 31, 2005.

10. Cumulative Preferred Shares and Class B Stock Options of Subsidiary

Cumulative Preferred Shares — All four series of cumulative preferred shares are redeemable at the option of the Company. As of December 31, 2005 the call price by series is:

Series outstanding	Call price
$3.60, 60,000 shares	$	102.25
$4.40, 25,000 shares	$	102.00
$4.65, 30,000 shares	$	101.50
$6.75, 40,000 shares	$	102.70

Class B Stock Options of Subsidiary — In connection with the acquisition of IPH in August 2004, IPH management and certain other employees elected to retain stock options for the purchase of 1,112 IPH Class B common shares valued at $1.8 million. The options are exercisable at any time and the option holder must deliver cash to exercise the option. Once the options are exercised for Class B shares, the Class B shareholder cannot put the shares back to the Company for 181 days. At that time, the Class B common shares are redeemable at any time during the employment of the individual holder, subject to certain limits on the total number of Class B common shares redeemable on an annual basis. The Class B common shares are non-voting, except in the event of a merger, and do not participate in dividends but have liquidation rights at par with the Class A common shares owned by the Company. The value of the Class B common shares issued on exercise of the options represents an interest in IPH that changes as defined in the agreement.

In 2005, options for 357 IPH Class B common shares were exercised. Total cash paid to IPH on exercise of the options and issuance of the Class B common shares was $171,000. The Class B common shares were redeemed by IPH 181 days after issuance and prior to December 31, 2005 for $745,000, the value of the shares on the date of issuance. The combined exercise price of the remaining 755 options outstanding on December 31, 2005 was $316,000.

11. Pension Plan and Other Postretirement Benefits

Effective July 1, 2005 the Company remeasured its pension and other postretirement benefit plan obligations using the RP-2000 Combined Healthy Mortality table in place of the 1983 Group Annuity Mortality table (GAM ’83) it used to measure its obligations and determine its annual costs under these plans in January 2005. The reason for the remeasurement was to update the mortality table to more accurately reflect current life expectancies of current employees and retirees included in the plans. Generally accepted accounting principles require that all assumptions used to measure plan obligations and determine annual plan costs be revised as of a remeasurement date. The following actuarial assumptions were updated as of the July 1, 2005 remeasurement date:

	January 1, 2005 through	July 1, 2005 through
Key assumptions and data	June 30, 2005	December 31, 2005
Discount rate	6.00%	5.25%
Long-term rate of return on plan assets	8.50%	8.50%
Social Security wage base	4.00%	3.50%
Rate of inflation	3.00%	2.50%
Rate of withdrawal	1% per year through age 54	2% per year through age 54
Mortality table	GAM ‘83	RP-2000 projected to 2006
Market value of assets — beginning of period	$141,685,000	$142,547,832

Remeasuring the Company’s pension and other postretirement benefit plan obligations as of July 1, 2005, under the revised assumptions had the effect of increasing the Company’s 2005 projected pension plan costs by $1,364,000, increasing its 2005 projected Executive Survivor and Supplemental Retirement Plan costs by $123,000 and increasing its 2005 projected costs for postretirement benefits other than pensions by $137,000.

Pension Plan—The Company’s noncontributory funded pension plan covers substantially all electric utility and corporate employees. The plan provides 100% vesting after five vesting years of service and for retirement compensation at age 65, with reduced compensation in cases of retirement prior to age 62. The Company reserves the right to discontinue the plan but no change or discontinuance may affect the pensions theretofore vested. The Company’s policy is to fund pension costs accrued. All past service costs have been provided for.

The pension plan has a trustee who is responsible for pension payments to retirees. Four investment managers are responsible for managing the plan’s assets. An independent actuary performs the necessary actuarial valuations for the plan.

The plan assets consist of common stock and bonds of public companies, U.S. government securities, cash and cash equivalents. None of the plan assets are invested in common stock, preferred stock or debt securities of the Company.

The following tables provide a reconciliation of the changes in the plan’s benefit obligations and fair value of assets over the two-year period ended December 31, 2005 and a statement of the funded status as of December 31 of both years:

	2005			2004
	(in thousands)
Reconciliation of benefit obligation:
Obligation at January 1	$	166,190		$	154,159
Service cost		4,695			4,063
Interest cost		9,721			9,458
Benefit payments		(8,567	)		(8,600	)
Plan amendments		222			—
Actuarial loss		9,326			7,110
Obligation at December 31	$	181,587		$	166,190
Reconciliation of fair value of plan assets:
Fair value of plan assets at January 1	$	141,685		$	132,811
Actual return on plan assets		9,864			13,474
Discretionary company contributions		4,000			4,000
Benefit payments		(8,567	)		(8,600	)
Fair value of plan assets at December 31	$	146,982		$	141,685
Funded status	$	(34,605	)	$	(24,505	)
Unrecognized net actuarial loss		38,777			28,607
Unrecognized prior service cost		5,623			6,127
Net amount recognized	$	9,795		$	10,229

     The following table provides the amounts recognized in the consolidated balance sheets as of December 31:

	2005			2004
	(in thousands)
Prepaid pension cost	$	9,795		$	10,229
Additional minimum liability		(13,380	)		—
Net pension asset/(liability)	$	(3,585	)	$	10,229
Intangible asset		5,623			—
Accumulated other comprehensive loss		7,757			—
Net amount recognized	$	9,795		$	10,229

     Additional information on the status of the pension plan as of December 31:

	2005		2004
	(in thousands)
Projected benefit obligation	$	181,587	$	166,190
Accumulated benefit obligation		150,567		137,682
Fair value of plan assets		146,982		141,685

Components of net periodic pension benefit cost:

	2005			2004			2003
	(in thousands)
Service cost—benefit earned during the period	$	4,695		$	4,063		$	3,779
Interest cost on projected benefit obligation		9,721			9,458			9,491
Expected return on assets		(12,071	)		(12,438	)		(12,933	)
Amortization of prior-service cost		726			897			1,170
Amortization of net actuarial loss		1,364			—			—
Net periodic pension cost	$	4,435		$	1,980		$	1,507

The change in the additional minimum liability included in Accumulated other comprehensive loss was $7,757,000 in 2005 and $0 in 2004.

Weighted-average assumptions used to determine benefit obligations at December 31:

	2005			2004
Discount rate		5.75	%		6.00	%
Rate of increase in future compensation level		3.75	%		3.75	%

Weighted-average assumptions used to determine net periodic pension cost for the year ended December 31:

	2005			2004
Discount rate (2005 is remeasurement composite rate)		5.625	%		6.25	%
Long-term rate of return on plan assets		8.50	%		8.50	%
Rate of increase in future compensation level		3.75	%		3.75	%

To develop the expected long-term rate of return on assets assumption, the Company considered the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of the pension portfolio.

The assumed rate of return on pension fund assets for the determination of 2006 net periodic pension cost is 8.5%.

The Company’s pension plan asset allocations at December 31, 2005 and 2004, by asset category are as follows:

Asset Allocation	2005			2004
Large capitalization equity securities		51.2	%		48.4	%
Small capitalization equity securities		11.4	%		11.2	%
International equity securities		9.8	%		14.7	%
Total equity securities		72.4	%		74.3	%
Cash and fixed-income securities		27.6	%		25.7	%
		100.0	%		100.0	%

The following objectives guide the investment strategy of the Company’s pension plan (the Plan).

• The Plan is managed to operate in perpetuity.

• The Plan will meet the pension benefit obligation payments of Otter Tail Corporation.

• The Plan’s assets should be invested with the objective of meeting current and future payment requirements while minimizing annual contributions and their volatility.

• The asset strategy reflects the desire to meet current and future benefit payments while considering a prudent level of risk and diversification.

The asset allocation strategy developed by the Company’s Retirement Plans Administrative Committee is based on the current needs of the Plan, the investment objectives listed above, the investment preferences and risk tolerance of the committee and a desired degree of diversification.

The asset allocation strategy contains guideline percentages, at market value, of the total Plan invested in various asset classes. The strategic target allocation shown in the table that follows is a guide that will at times not be reflected in actual asset allocations that may be dictated by prevailing market conditions, independent actions of the Retirement Plans Administrative Committee and/or investment managers, and required cash flows to and from the Plan. The tactical range provides flexibility for the investment managers’ portfolios to vary around the target allocation without the need for immediate rebalancing. The Company’s Retirement Plans Administrative Committee monitors actual asset allocations and directs contributions and withdrawals toward maintaining the targeted allocation percentages listed in the table below.

Asset Allocation	Strategic Target	Tactical Range
Large capitalization equity securities	48%	40%-55%
Small capitalization equity securities	12%	9%-15%
International equity securities	10%	5%-15%
Total equity securities	70%	60%-80%
Fixed-income securities	30%	20%-40%

        Cash Flows

The Company is not required to make a contribution to the pension plan in 2006.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

(in thousands)									Years
2006	2007		2008		2009		2010		2011-2015
$8,601	$	8,687	$	8,834	$	9,013	$	9,183	$	52,747

Executive Survivor and Supplemental Retirement Plan (ESSRP)—The ESSRP is an unfunded, nonqualified benefit plan for executive officers and certain key management employees. The ESSRP provides defined benefit payments to these employees on their retirements for life or to their beneficiaries on their deaths for a 15-year postretirement period. Life insurance carried on certain plan participants is payable to the Company on the employee’s death. There are no plan assets in this nonqualified benefit plan due to the nature of the plan.

On January 31, 2005 the Board of Directors of the Company amended and restated the ESSRP to reduce future benefits effective January 1, 2005, which resulted in reduced expense to the Company.

Effective January 1, 2005 new participants in the ESSRP accrue benefits under a new formula. The new formula is the same as the formula used under the Company’s qualified defined benefit pension plan but includes bonuses in the computation of covered compensation and is not subject to statutory compensation and benefit limits. Individuals who became participants in the ESSRP before January 1, 2005 will receive the greater of the old formula or the new formula until December 31, 2010. On December 31, 2010, their benefit under the old formula will be frozen. After 2010, they will receive the greater of their frozen December 31, 2010 benefit or their benefit calculated under the new formula. The amendments to the ESSRP also provide for increased service credits for certain participants and eliminate certain distribution features.

The following tables provide a reconciliation of the changes in the plan’s benefit obligations over the two-year period ended December 31, 2005 and a statement of the funded status as of December 31 of both years:

	2005			2004
	(in thousands)
Reconciliation of benefit obligation:
Obligation at January 1	$	23,123		$	24,451
Service cost		406			820
Interest cost		1,267			1,489
Plan amendments		(663	)		—
Actuarial loss (gain)		232			(2,543	)
Benefit payments		(1,094	)		(1,094	)
Obligation at December 31	$	23,271		$	23,123
Funded status:
Funded status at December 31	$	(23,271	)	$	(23,123	)
Unrecognized prior-service cost		891			1,626
Unrecognized net actuarial loss		8,471			8,737
Net amount recognized	$	(13,909	)	$	(12,760	)

The following table provides the amounts recognized in the consolidated balance sheets as of December 31:

	2005			2004
	(in thousands)
Accrued benefit liability	$	(19,631	)	$	(16,703	)
Intangible asset		891			1,626
Accumulated other comprehensive loss		4,831			2,317
Net amount recognized	$	(13,909	)	$	(12,760	)

     Additional information on the ESSRP defined benefit pension plan as of December 31:

	2005		2004
	(in thousands)
Projected benefit obligation	$	23,271	$	23,123
Accumulated benefit obligation		19,631		16,703
Fair value of plan assets		—		—

Components of net periodic pension benefit cost:

	2005		2004		2003
	(in thousands)
Service cost—benefit earned during the period	$	406	$	820	$	417
Interest cost on projected benefit obligation		1,267		1,489		1,426
Amortization of prior-service cost		71		147		147
Recognized net actuarial loss		498		680		573
Total	$	2,242	$	3,136	$	2,563

 The change in the additional minimum liability included in Accumulated other comprehensive loss was $2,514,000 in 2005 and ($2,112,000) in 2004.

Weighted-average assumptions used to determine benefit obligations at December 31:	2005			2004
Discount rate		5.75	%		6.00	%
Rate of increase in future compensation level		4.69	%		4.69	%

Weighted-average assumptions used to determine net periodic pension cost for the year ended December 31:	2005			2004
Discount rate (2005 is remeasurement composite rate)		5.625	%		6.25	%
Rate of increase in future compensation level		4.69	%		5.88	%

Cash Flows

The ESSRP is unfunded and has no assets; contributions are equal to the benefits paid to plan participants. The following benefit payments, which reflect future service, as appropriate, are expected to be paid:

(in thousands)									Years
2006	2007		2008		2009		2010		2011-2015
$1,132	$	1,128	$	1,114	$	1,120	$	1,116	$	6,326

Other Postretirement Benefits—The Company provides a portion of health insurance and life insurance benefits for retired electric utility and corporate employees. Substantially all of the Company’s electric utility and corporate employees may become eligible for health insurance benefits if they reach age 55 and have 10 years of service. On adoption of SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, in January 1993, the Company elected to recognize its transition obligation related to postretirement benefits earned of approximately $14,964,000 over a period of 20 years. There are no plan assets.

During the third quarter of 2004, the Company adopted FASB Staff Position No. FAS 106-2 (FSP 106-2), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 retroactive to the beginning of 2004. The Company and its actuarial advisors determined that the expected federal subsidy reduced the Company’s accumulated postretirement benefit obligation (APBO) at January 1, 2004 by $4,935,000 and reduced its net periodic benefit cost for 2004 by $757,000. The APBO reduction was accounted for as an actuarial experience gain in accordance with the guidance in SFAS No. 106 and was not included as a reduction to the net periodic benefit cost in 2004.

The following tables provide a reconciliation of the changes in the plan’s benefit obligations over the two-year period ended December 31, 2005 and a statement of the funded status as of December 31 of both years:

	2005			2004
	(in thousands)
Reconciliation of benefit obligation:
Obligation at January 1	$	39,639		$	42,008
Service cost		1,172			1,133
Interest cost		1,998			2,271
Benefit payments		(3,112	)		(3,449	)
Participant premium payments		1,320			1,134
Decrease due to Medicare Part D subsidy		—			(4,935	)
Actuarial (gain) loss		(4,260	)		1,477
Obligation at December 31	$	36,757		$	39,639
Funded status:
Funded status at December 31	$	(36,757	)	$	(39,639	)
Unrecognized transition obligation		5,237			5,985
Unrecognized prior-service cost		1,310			1,005
Unrecognized loss		3,228			7,596
Net amount recognized	$	(26,982	)	$	(25,053	)

The net amounts recognized are shown on the consolidated balance sheets as of December 31, 2005 and 2004 under Other postretirement benefits liability.

Components of net periodic postretirement benefit cost:

	2005			2004			2003
	(in thousands)
Service cost	$	1,307		$	1,170		$	1,009
Interest cost		2,480			2,580			2,619
Amortization of transition obligation		748			748			748
Amortization of prior-service cost		(305	)		(305	)		(305	)
Amortization of net loss		742			702			708
Expense decrease due to Medicare Part D subsidy		(1,251	)		(757	)		—
Net periodic postretirement benefit cost	$	3,721		$	4,138		$	4,779

Weighted-average assumptions used to determine benefit obligations at December 31:	2005			2004
Discount rate		5.75	%		6.00	%

Weighted-average assumptions used to determine net periodic postretirement benefit cost for the year ended December 31:	2005			2004
Discount rate (2005 is remeasurement composite rate)		5.625	%		6.25	%

     Assumed healthcare cost-trend rates as of December 31:

	2005			2004
Healthcare cost-trend rate assumed for next year		9.0	%		10.0	%
Rate at which the cost-trend rate is assumed to decline		5.0	%		5.0	%
Year the rate reaches the ultimate trend rate		2010			2010

Assumed healthcare cost-trend rates have a significant effect on the amounts reported for healthcare plans. A one-percentage-point change in assumed healthcare cost-trend rates for 2005 would have the following effects:

	1 point		1 point
	increase		decrease
	(in thousands)
Effect on total of service and interest cost	$	516	$	(415	)
Effect on the postretirement benefit obligation	$	4,574	$	(3,808	)

Cash Flows

The Company expects to contribute $2.4 million net of expected employee contributions for the payment of retiree medical benefits in 2006. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

(in thousands)									Years
2006	2007		2008		2009		2010		2011-2015
$2,380	$	2,488	$	2,549	$	2,610	$	2,593	$	14,127

The Company expects to receive a Medicare Part D subsidy from the Federal government of approximately $350,000 in 2006.

Leveraged Employee Stock Ownership Plan—The Company has a leveraged employee stock ownership plan for the benefit of all its electric utility employees. Contributions made by the Company were $830,000 for 2005, $930,000 for 2004 and $1,030,000 for 2003.

12. Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash and Short-Term Investments—The carrying amount approximates fair value because of the short-term maturity of those instruments.

Other Investments—The carrying amount approximates fair value. A portion of other investments is in financial instruments that have variable interest rates that reflect fair value. The remainder of other investments is accounted for by the equity method which, in the case of operating losses, results in a reduction of the carrying amount.

Long-Term Debt—The fair value of the Company’s long-term debt is estimated based on the current rates available to the Company for the issuance of debt. About $22.0 million of the Company’s long-term debt, which is subject to variable interest rates, approximates fair value.

	December 31, 2005						December 31, 2004
	(in thousands)
	Carrying			Fair			Carrying			Fair
	amount			value			amount			value
Cash and short-term investments	$	5,430		$	5,430		$	—		$	—
Other investments		8,702			8,702			14,450			14,450
Long-term debt		(258,260	)		(273,456	)		(261,805	)		(294,020	)

13. Property, Plant and Equipment

	2005		2004
	(December 31, in thousands)
Electric plant:
Production	$	357,285	$	347,800
Transmission		182,502		180,150
Distribution		296,301		285,253
General		74,678		76,997
Electric plant		910,766		890,200
Less accumulated depreciation and amortization		374,786		363,696
Electric plant net of accumulated depreciation		535,980		526,504
Construction work in progress		12,449		12,212
Net electric plant	$	548,429	$	538,716
Nonelectric operations plant	$	228,548	$	208,311
Less accumulated depreciation and amortization		84,652		73,160
Nonelectric plant net of accumulated depreciation		143,896		135,151
Construction work in progress		4,766		6,257
Net nonelectric operations plant	$	148,662	$	141,408
Net plant	$	697,091	$	680,124

The estimated service lives for rate-regulated properties is 5 to 65 years. For nonelectric property the estimated useful lives are from 3 to 40 years.

	Service Life Range
(years)	Low		High
Electric fixed assets:
Production plant		34		62
Transmission plant		40		55
Distribution plant		15		55
General plant		5		65
Nonelectric fixed assets		3		40

14. Income Taxes

The total income tax expense differs from the amount computed by applying the federal income tax rate (35% in 2005, 2004 and 2003) to net income before total income tax expense for the following reasons:

	2005			2004			2003
	(in thousands)
Tax computed at federal statutory rate	$	28,288		$	20,327		$	18,335
Increases (decreases) in tax from:
State income taxes net of federal income tax		1,903			1,815			1,837
Investment tax credit amortization		(1,151	)		(1,152	)		(1,152	)
Differences reversing in excess of federal rates		(15	)		(136	)		(1,283	)
Dividend received/paid deduction		(703	)		(703	)		(707	)
Affordable housing tax credits		(1,324	)		(1,418	)		(1,412	)
Permanent and other differences		969			(1,286	)		(1,456	)
Total income tax expense	$	27,967		$	17,447		$	14,162
Income tax expense — discontinued operations	$	5,610		$	1,040		$	768
Overall effective federal and state income tax rate		34.9	%		30.5	%		27.4	%
Income tax expense includes the following:
Current federal income taxes	$	32,760		$	15,299		$	11,101
Current state income taxes		5,260			2,923			2,821
Deferred federal income taxes		(7,112	)		1,776			2,809
Deferred state income taxes		(899	)		194			(5	)
Affordable housing tax credits		(1,324	)		(1,418	)		(1,412	)
Investment tax credit amortization		(1,151	)		(1,152	)		(1,152	)
Foreign income taxes		433			(175	)		—
Total	$	27,967		$	17,447		$	14,162

The Company’s deferred tax assets and liabilities were composed of the following on December 31, 2005 and 2004:

	2005			2004
	(in thousands)
Deferred tax assets
Amortization of tax credits	$	5,964		$	6,698
Vacation accrual		2,432			2,191
Unearned revenue		2,803			2,095
Benefit liabilities		29,657			20,882
Cost of removal		20,507			19,431
Differences related to property		7,400			6,565
Transfer to regulatory liability		—			31
Other		3,689			2,853
Total deferred tax assets	$	72,452		$	60,746
Deferred tax liabilities
Differences related to property	$	(154,833	)	$	(155,175	)
Excess tax over book pension		(3,861	)		(4,041	)
Transfer to regulatory asset		(16,724	)		(14,528	)
Other		(3,900	)		(3,451	)
Total deferred tax liabilities	$	(179,318	)	$	(177,195	)
Deferred income taxes	$	(106,866	)	$	(116,449	)

15. Discontinued Operations

In 2005, the Company completed the sales of Midwest Information Systems, Inc. (MIS), St. George Steel Fabrication, Inc. (SGS) and Chassis Liner Corporation (CLC). Discontinued operations includes the operating results of MIS, SGS and CLC for 2005, 2004 and 2003. Discontinued operations also includes an after-tax gain on the sale of MIS of $11.9 million, an after-tax loss on the sale of SGS of $1.7 million and an after-tax loss on the sale of CLC of $0.2 million in 2005. MIS, SGS and CLC meet requirements to be reported as discontinued operations in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.

The results of discontinued operations for the years ended December 31, 2005, 2004 and 2003 are summarized as follows:

	2005
(in thousands)	MIS		SGS			CLC			Total
Operating revenues	$	3,773	$	6,564		$	6,112		$	16,449
Income (loss) before income taxes		2,167		(1,740	)		(956	)		(529	)
Gain (loss) on disposition — pretax		19,025		(2,919	)		(271	)		15,835
Income tax expense (benefit)		7,975		(1,863	)		(502	)		5,610

	2004
(in thousands)	MIS		SGS			CLC			Total
Operating revenues	$	8,739	$	17,209		$	7,753		$	33,701
Income (loss) before income taxes		3,698		(932	)		(163	)		2,603
Income tax expense (benefit)		1,483		(371	)		(72	)		1,040

	2003
(in thousands)	MIS		SGS			CLC			Total
Operating revenues	$	8,547	$	12,160		$	8,244		$	28,951
Income (loss) before income taxes		3,408		(938	)		(271	)		2,199
Income tax expense (benefit)		1,367		(383	)		(216	)		768

At December 31, 2005 and 2004 the major components of assets and liabilities of the discontinued operations were as follows:

	December 31, 2005						December 31, 2004
(in thousands)	SGS		CLC		Total		MIS		SGS		CLC		Total
Current assets	$	857	$	1,455	$	2,312	$	275	$	9,344	$	3,092	$	12,711
Investments and other assets		—		5		5		2,270		—		5		2,275
Goodwill—net		—		—		—		5,925		—		—		5,925
Other intangibles—net		—		—		—		—		18		74		92
Net plant		—		—		—		7,960		1,618		356		9,934
Assets of discontinued operations	$	857	$	1,460	$	2,317	$	16,430	$	10,980	$	3,527	$	30,937
Current liabilities	$	328	$	44	$	372	$	2,920	$	2,228	$	837	$	5,985
Deferred credits		—		—		—		581		271		33		885
Long-term debt		—		—		—		1,710		—		5		1,715
Liabilities of discontinued operations	$	328	$	44	$	372	$	5,211	$	2,499	$	875	$	8,585

The remaining assets and liabilities of SGS and CLC primarily consist of accounts receivable, inventory and accounts payable at estimated fair market values that were not settled or disposed of as of December 31, 2005.

16. Asset Retirement Obligations (AROs)

The Company’s AROs are related to coal-fired generation plants and include site restoration, the closure of ash pits and the removal of storage tanks and asbestos. The Company has legal obligations associated with the retirement of various other long-lived assets used in its electric operations where the estimated settlement costs are individually and collectively immaterial. There are no assets legally restricted for the settlement of any of the Company’s AROs.

The present value of the legal AROs as of December 31, 2005 of $1,524,000 is included in Other noncurrent liabilities on the Company’s December 31, 2005 consolidated balance sheet. The ARO liability includes the capitalized fair value of the obligations of $349,000; accumulated accretion as of December 31, 2004 of $1,088,000 plus the 2005 accretion provision of $87,000.

The present value of the legal AROs as of December 31, 2004 was $1,437,000, which includes the original obligation of $377,000 less a 2004 subsequent measurement adjustment of $28,000 plus accumulated accretion expense of $1,088,000.

17. Quarterly Information (not audited)

Because of changes in the number of common shares outstanding and the impact of diluted shares, the sum of the quarterly earnings per common share may not equal total earnings per common share.

	Three Months Ended
	March 31					June 30				September 30					December 31
	2005			2004		2005		2004		2005			2004		2005			2004
	(in thousands, except per share data)
Operating revenues (a)	$	232,133		$	199,583	$	256,378	$	203,457	$	272,658		$	214,719	$	285,239		$	239,603
Operating income (a)		21,067			16,202		20,868		15,071		32,356			20,073		23,303			24,068
Net Income:
Continuing operations		11,050			8,258		10,967		7,808		18,080			10,669		12,758			13,897
Discontinued operations		(1,079	)		1		11,337		224		(477	)		357		(85	)		981
		9,971			8,259		22,304		8,032		17,603			11,026		12,673			14,878
Earnings available for common shares:
Continuing operations		10,866			8,074		10,784		7,624		17,895			10,485		12,575			13,713
Discontinued operations		(1,079	)		1		11,337		224		(477	)		357		(85	)		981
		9,787			8,075		22,121		7,848		17,418			10,842		12,490			14,694
Basic earnings per share:
Continuing operations	$	.37		$	.31	$	.37	$	.29	$	.61		$	.40	$	.43		$	.51
Discontinued operations		(.03	)		—		.39		.01		(.01	)		.02		—			.04
		.34			.31		.76		.30		.60			.42		.43			.55
Diluted earnings per share:
Continuing operations	$	.37		$	.31	$	.37	$	.29	$	.61		$	.40	$	.42		$	.51
Discontinued operations		(.04	)		—		.39		.01		(.02	)		.02		—			.04
		.33			.31		.76		.30		.59			.42		.42			.55
Dividends paid per common share		.28			.275		.28		.275		.28			.275		.28			.275
Price range:
High	$	25.87		$	27.50	$	27.77	$	27.19	$	31.95		$	26.96	$	31.95		$	27.36
Low		24.17			26.00		24.02		24.07		27.20			23.77		26.76			24.99
Average number of common shares outstanding—basic		29,126			25,793		29,158		25,891		29,246			26,010		29,361			26,663
Average number of common shares outstanding—diluted		29,230			25,936		29,264		26,014		29,441			26,122		29,555			26,780

(a) From continuing operations.

Stock Listing

Otter Tail Corporation common stock trades on The Nasdaq Stock Market.

EX-10.N.7

Exhibit 10-N-7

OTTER TAIL CORPORATION
1999 STOCK INCENTIVE PLAN
2005 NONQUALIFIED STOCK OPTION AGREEMENT

     This 2005 Nonqualified Stock Option Agreement between Otter Tail Corporation, a Minnesota corporation (the “Corporation”), and the person named in the attached Stock Option Award Certificate who is an employee of the Corporation or one of its Affiliates (the “Optionee”), effective as of the date of grant set forth in the attached Stock Option Award Certificate (the “Grant Date”).

     WHEREAS, the Corporation desires to provide the Optionee with an opportunity to purchase shares of the Corporation’s Common Stock, par value $5.00 per share (the “Common Shares”), as hereinafter provided in order to carry out the purpose of the Corporation’s 1999 Stock Incentive Plan (the “Plan”).

     WHEREAS, this 2005 Nonqualified Stock Option Agreement applies to all options with a Grant Date of January 2005 and thereafter (the “Effective Date”). No change is intended or made to Options issued prior to the Effective Date.

     NOW, THEREFORE, for good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the Corporation and the Optionee hereby agree as follows:

     1. Grant of Option. The Corporation hereby grants to the Optionee the right and option (the “Option”) to purchase all or any part of the aggregate number of Common Shares set forth in the attached Stock Option Award Certificate, on the terms and conditions set forth in this Agreement and the Plan. The Option granted hereunder shall not be an incentive stock option within the meaning of Section 422 of the Internal Revenue Code of 1986, as amended (the “Code”).

     2. Exercise Price. The per share purchase price of the Common Shares subject to the Option shall be the option price per share set forth in the attached Stock Option Award Certificate.

     3. Duration and Exercisability. The term of the Option shall be for a period of ten years from the Grant Date, terminating at the close of business on the expiration date set forth in the attached Stock Option Award Certificate (the “Expiration Date”) or such shorter period as is prescribed in paragraph 6 hereof. The Option becomes exercisable in its entirety on October 11, 2005, subject to the provisions of paragraphs 4 and 6 hereof. Except as provided in paragraph 6 hereof, the Option may not be exercised unless the Optionee shall, at the time of exercise, be an employee of the Corporation or one of its Affiliates. The Optionee shall not have any of the rights of a shareholder with respect to any of the Common Shares subject to the Option until such shares shall be issued to the Optionee upon due exercise of the Option.

     4. Change of Control. Notwithstanding the provisions of paragraph 3 hereof, from and after a Change of Control (as hereinafter defined) the Option shall become immediately exercisable in full. As used herein, “Change of Control” shall mean any of the following events:

     (a) The acquisition by any person, entity or “group,” within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), other than the Corporation or any of its Affiliates, or any employee benefit plan of the Corporation and/or one or more of its Affiliates, of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 15% or more of either the then outstanding Common Shares or the combined voting power of the Corporation’s then outstanding voting securities in a transaction or series of transactions not approved in advance by a vote of at least three-quarters of the Continuing Directors (as hereinafter defined); or

     (b) Individuals who, as of the Grant Date, constitute the Board of Directors of the Corporation (generally the “Directors” and as of the Grant Date the “Continuing Directors”) cease for any reason to constitute at least a majority thereof, provided that any person becoming a Director subsequent to the Grant Date whose nomination for election was approved in advance by a vote of at least three-quarters of the Continuing Directors (other than a nomination of an individual whose initial assumption of office is in connection with an actual or threatened solicitation with respect to the election or removal of the Directors of the Corporation, as such terms are used in Rule 14a-11 of Regulation 14A under the Exchange Act) shall be deemed to be a Continuing Director; or

     (c) The approval by the shareholders of the Corporation of a reorganization, merger, consolidation, liquidation or dissolution of the Corporation or of the sale (in one transaction or a series of related transactions) of all or substantially all of the assets of the Corporation other than a reorganization, merger, consolidation, liquidation, dissolution or sale approved in advance by a vote of at least three-quarters of the Continuing Directors;

     (d) The first purchase under any tender offer or exchange offer (other than an offer by the Corporation or any of its Affiliates) pursuant to which Common Shares are purchased; or

     (e) At least a majority of the Continuing Directors determines in their sole discretion that there has been a change in control of the Corporation.

     5. Transferability. The Option shall not be transferable other than by will or the laws of descent and distribution, and the Option may be exercised during the lifetime of the Optionee only by the Optionee. More particularly (but without limiting the generality of the foregoing), the Option may not be assigned, transferred (except as aforesaid), pledged or hypothecated in any way (whether by operation of law or otherwise) and shall not be subject to execution, attachment or similar process. Any attempted assignment, transfer, pledge, hypothecation, or other disposition of the Option contrary to the provisions hereof and the levy of an execution, attachment or similar process upon the Option shall be void. Notwithstanding the foregoing,

2

Optionee may, in the manner established by the Committee, designate a beneficiary or beneficiaries to exercise the rights of the Optionee with respect to the Option upon the death of the Optionee.

     6. Effect of Termination of Employment.

          (a) In the event the Optionee shall cease to be employed by the Corporation or any of its Affiliates for any reason other than termination for cause, death, disability, termination within two years following a Change in Control, or retirement after reaching age 55, the Optionee may exercise the Option at any time within three months after such termination of employment, but not thereafter; provided, however, that the Option may not be exercised after the Expiration Date and may be exercised only to the extent of the number of shares the Optionee was entitled to purchase under the Option on the date of such termination.

          (b) In the event the Optionee shall cease to be employed by the Corporation or any of its Affiliates upon termination for cause, the Option shall be terminated as of the date of such termination. Termination for cause shall mean termination of Optionee’s employment with the Corporation or any of its Affiliates for the following acts: dishonesty, fraud, conviction or confession of a felony or of a crime involving moral turpitude, destruction or theft of the property of the Corporation or any of its Affiliates, willful malfeasance or gross negligence, misconduct materially injurious to the Corporation or any of its Affiliates, participation in fraud against the Corporation or any of its Affiliates, entering into competition against the Corporation or any of its Affiliates, and/or a material breach or threatened material breach of any other agreements with the Corporation or any of its Affiliates.

          (c) In the event the Optionee shall cease to be employed by the Corporation or any of its Affiliates within two years following a Change in Control, the Optionee may exercise the Option at any time after such termination of employment, provided, however, that the Option may not be exercised after the Expiration Date.

          (d) In the event the Optionee terminates employment due to retirement from the Corporation or any of its Affiliates after reaching age 55, the Option shall remain in full force and effect, and continue to vest in accordance with paragraph 3 hereof.

          (e) In the event that the Optionee shall cease to be employed by the Corporation or any of its Affiliates as the result of death or disability, or the Optionee shall die within three months after the termination of the Optionee’s employment other than for cause, the Option may be exercised by the Optionee or, if applicable, by the Optionee’s personal representative or administrator or by any person or persons to whom the Option is transferred by will or the applicable laws of descent and distribution, at any time within a period of one year after the termination of employment of the Optionee, but not after the Expiration Date, to the full extent of the Common Shares covered by the Option not previously purchased, whether or not such shares had become purchasable by the Optionee at the date of the Optionee’s termination of employment. For purposes of this Agreement, an Optionee shall be deemed to have a disability if such Optionee is deemed to be disabled under any long-term disability program then

3

maintained by the Corporation or any of its Affiliates that is applicable to the Optionee; provided, however, that if no such long-term plan is then maintained, the determination of disability shall be in the exclusive and sole discretion of the Corporation.

     (f) The Option shall not be affected by any change of the duties or position of the Optionee (or by a temporary leave of absence approved by the Corporation) so long as the Optionee continues to be an employee of the Corporation or of an Affiliate.

     (g) Nothing herein contained shall confer on the Optionee any right to continue in the employ of the Corporation or any Affiliate or affect in any way the right of the Corporation or any Affiliate to terminate the employment of the Optionee at any time.

     7. Anti-dilution Adjustments. If any portion of the Option is exercised subsequent to any stock dividend, split-up, recapitalization, merger, consolidation, combination or exchange of shares or the like occurring after the Grant Date as a result of which shares of any class shall be issued in respect of the outstanding Common Shares, or Common Shares shall be changed into the same or a different number of shares of the same or another class or classes, the person or persons exercising the Option shall receive for the aggregate price paid upon such exercise the aggregate number of shares which, if Common Shares (as authorized at the Grant Date) had been purchased at the Grant Date for the same aggregate price (on the basis of the price per share set forth in paragraph 2 hereof) and had not been disposed of, such person or persons would be holding at the time of such exercise as a result of such purchase and any and all such stock dividends, split-ups, recapitalizations, mergers, consolidations, combinations or exchanges of shares, or the like; provided, however, that no fractional share shall be issued upon any such exercise, and the aggregate price paid shall be appropriately reduced on account of any fractional share not issued.

     8. Manner of Exercise. The Option may be exercised by written notice to Wells Fargo Investment, LLC as prescribed by the Corporation. The notice shall state the number of shares with respect to which the Option is being exercised. The notice shall be accompanied by payment of the full purchase price and the Corporation or its agent shall issue and deliver a certificate representing such shares as soon as practicable after the notice is received. Payment of the purchase price shall, unless otherwise consented to by the Corporation, be made by delivery of cash, check (bank check, certified check or personal check) or money order payable to the order of the Corporation Certificates for the shares purchased shall be registered in the name of the person exercising the Option (or if the Option shall be exercised by the Optionee and if the Optionee shall so request in the notice exercising the Option, shall be registered in the name of the Optionee and another person as joint tenants) and shall be delivered to the person exercising the Option. In the event the Option shall be exercised pursuant to paragraph 6(d) hereof by any person other than the Optionee, the notice shall be accompanied by appropriate proof of such person’s right to exercise the Option. All shares issued upon the exercise of the Option shall be fully paid and non-assessable.

     9. Taxes. The Optionee acknowledges that the Optionee will consult with the Optionee’s personal tax advisor regarding the income tax consequences of exercising the Option

4

or any other matters related to this Agreement. In order to provide the Corporation with the opportunity to claim the benefit of any income tax deduction which may be available to it upon exercise of the Option, and in order to comply with all applicable income tax laws or regulations, the Corporation may take such action as it deems appropriate to insure that, if necessary, all applicable federal or state payroll, withholding, income or other taxes are withheld or collected from the Optionee. In accordance with the terms of the Plan, and such rules as may be adopted by the Committee under the Plan, the Optionee may elect to satisfy the Optionee’s federal and state income tax withholding obligations upon exercise of the Option by (a) delivering cash, check (bank check, certified check or personal check) or money order payable to the order of the Corporation, or (b) having the Corporation withhold a portion of the Common Shares otherwise to be delivered upon exercise of the Option having a Fair Market Value equal to the amount of federal and state income tax required to be withheld upon such exercise, in accordance with such rules as the Corporation may from time to time establish.

     10. Miscellaneous.

          (a) The Corporation shall reserve and keep available such number of Common Shares as will be sufficient to satisfy the requirements of this Agreement.

          (b) If any of the shares covered by this Agreement are not registered under the Securities Act of 1933 at the time of their issuance hereunder, the Optionee represents and agrees that all such shares purchased under the Option will be acquired for investment and not for resale.

          (c) As used in this Agreement, the term “Common Shares” shall mean the Common Shares of the Corporation as authorized at the Grant Date, and the terms “Affiliate,” “Committee” and “Fair Market Value” shall have the meanings ascribed to them in the Plan.

          (d) This Option is granted pursuant to the Plan and is subject to all the terms and conditions contained therein. A copy of the Plan is available to the Optionee upon request.

          (e) This Agreement shall be governed by and construed in accordance with the laws of the State of Minnesota.

          (f) Headings in this Agreement are for convenience of reference only and shall not be deemed in any way to be material or relevant to the construction or interpretation of this Agreement or any provision hereof.

          (g) THIS 2005 NONQUALIFIED STOCK OPTION AGREEMENT IS ATTACHED TO AND MADE A PART OF A STOCK OPTION AWARD CERTIFICATE AND SHALL HAVE NO FORCE OR EFFECT UNLESS SUCH STOCK OPTION AWARD CERTIFICATE IS DULY EXECUTED AND DELIVERED BY THE CORPORATION AND THE OPTIONEE.

* * * * * * * *

5

OTTER TAIL CORPORATION
1999 STOCK INCENTIVE PLAN
STOCK OPTION AWARD CERTIFICATE

[Name and address of Optionee]

[Social Security Number of Optionee]

     You have been granted options to purchase shares of Otter Tail Corporation Common Stock as follows:

Grant Type:	Nonqualified Stock Option
Grant Date:	April 11, 2005
Stock Option Plan:	1999 Stock Incentive Plan
Option Price Per Share:	$
Total Number of Shares Granted:
Expiration Date:	April 11, 2015

     By the Corporation’s and your signature below, it is agreed that these options are granted under and governed by the terms and conditions of the 2005 Nonqualified Stock Option Agreement, a copy of which is attached and made a part of this document, and the Corporation’s 1999 Stock Incentive Plan, a copy of which is enclosed.

OTTER TAIL CORPORATION

OTTER TAIL CORPORATION
By:
	John Erickson
	Its: President & Chief Executive Officer
	[Name of Optionee]

6

EX-10.N.8

Exhibit 10-N-8

OTTER TAIL CORPORATION
1999 STOCK INCENTIVE PLAN
2005 RESTRICTED STOCK AWARD AGREEMENT
FOR EMPLOYEES

     This Restricted Stock Award Agreement for Employees is between Otter Tail Corporation, a Minnesota corporation (the “Corporation”), and the person named in the attached Restricted Stock Award Certificate for Employees who is an employee of the Corporation or one of its Affiliates (the “Participant”), effective as of the date of grant (the “Grant Date”) set forth in the attached Restricted Stock Award Certificate for Employees.

     WHEREAS, the Corporation, pursuant to the Otter Tail Corporation 1999 Stock Incentive Plan (the “Plan”), wishes to award to the Participant a number of the Corporation’s Common Shares, par value $5.00 per share (the “Common Shares”), subject to certain restrictions and on the terms and conditions contained in this Agreement and in the attached Restricted Stock Award Certificate for Employees, which is made a part hereof.

     NOW, THEREFORE, for good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the Corporation and the Participant hereby agree as follows:

     1. Award of Restricted Stock. The Corporation hereby grants to the Participant, effective as of the Grant Date, an award of restricted stock for that number of Common Shares set forth in the attached Restricted Stock Award Certificate for Employees (the “Shares”), on the terms and conditions set forth in this Agreement, the Restricted Stock Award Certificate for Employees and the 1999 Stock Incentive Plan.

     2. Rights of the Participant with Respect to the Shares. With respect to the Shares, the Participant shall be entitled at all times on and after the date of issuance of the Shares to exercise the rights of a shareholder of Common Shares of the Corporation, including the right to vote the Shares and the right to receive dividends thereon as provided in Section 8 hereof, unless and until the Shares are forfeited pursuant to Section 5(b) hereof. The rights of the Participant with respect to the Shares shall remain forfeitable at all times prior to the date or dates on which such rights become vested, and the restrictions with respect to the Shares lapse, in accordance with Section 3, 4 or 5(a) hereof.

     3. Vesting. Subject to the terms and conditions of this Agreement, the Shares shall vest, and the restrictions with respect to the Shares shall lapse, in installments on the dates and in the amounts set forth in the attached Restricted Stock Award Certificate for Employees if the Participant remains continuously employed by the Corporation or an Affiliate of the Corporation until the respective vesting dates.

     4. Change of Control. Notwithstanding the vesting provision contained in Section 3 above, but subject to the other terms and conditions set forth herein, upon the occurrence of a

Change of Control (as defined below) prior to any termination of the Participant’s employment, the Participant shall become immediately and unconditionally vested in all of the Shares, and the restrictions with respect to all of the Shares shall lapse. As used herein, “Change of Control” shall mean any of the following events:

     (a) The acquisition by any person, entity or “group,” within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), other than the Corporation or any of its Affiliates, or any employee benefit plan of the Corporation and/or one or more of its Affiliates, of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 15% or more of either the then outstanding Common Shares or the combined voting power of the Corporation’s then outstanding voting securities in a transaction or series of transactions not approved in advance by a vote of at least three-quarters of the Continuing Directors (as hereinafter defined); or

     (b) Individuals who, as of the Grant Date, constitute the Board of Directors of the Corporation (generally the “Directors” and as of the Grant Date the “Continuing Directors”) cease for any reason to constitute at least a majority thereof, provided that any person becoming a Director subsequent to the Grant Date whose nomination for election was approved in advance by a vote of at least three-quarters of the Continuing Directors (other than a nomination of an individual whose initial assumption of office is in connection with an actual or threatened solicitation with respect to the election or removal of the Directors of the Corporation, as such terms are used in Rule 14a-11 of Regulation 14A under the Exchange Act) shall be deemed to be a Continuing Director; or

     (c) The approval by the shareholders of the Corporation of a reorganization, merger, consolidation, liquidation or dissolution of the Corporation or of the sale (in one transaction or a series of related transactions) of all or substantially all of the assets of the Corporation other than a reorganization, merger, consolidation, liquidation, dissolution or sale approved in advance by a vote of at least three-quarters of the Continuing Directors;

     (d) The first purchase under any tender offer or exchange offer (other than an offer by the Corporation or any of its Affiliates) pursuant to which Common Shares are purchased; or

     (e) At least a majority of the Continuing Directors determines in their sole discretion that there has been a change in control of the Corporation.

     5. Additional Vesting Rules; Forfeiture.

          (a) If the Participant ceases to be employed by the Corporation or any of its Affiliates by reason of disability (as determined under any long-term disability program then maintained by the Corporation or any of its Affiliates that is applicable to the Participant), retirement (normal or early retirement under any retirement plan of the Corporation or any of its Affiliates that is applicable to the Participant) or death prior to the vesting of the Shares pursuant to Section 3 or 4 hereof, the shares shall continue to vest, and the restrictions with respect to the

2

shares shall lapse in installments on the dates and in the amounts set forth in the Restricted Stock Award Certificate for Employees for the benefit of the Participant or the Participant’s legal representatives, beneficiaries, or heirs as the case may be. No transfer by will or the applicable laws of descent and distribution of any Shares which vest by reason of the Participant’s death shall be effective to bind the Corporation unless the Committee shall have been furnished with written notice of such transfer and a copy of the will or such other evidence as the Committee may deem necessary to establish the validity of the transfer.

          (b) If the Participant elects to terminate the employment relationship with the Corporation or any of its Affiliates (unless for Good Reason as described in (c) below) or is terminated for cause, the Participant’s rights to all of the unvested Shares shall be immediately and irrevocably forfeited, including the right to vote such Shares and the right to receive cash dividends. Unless otherwise defined in an Employment Agreement dated on or before the Grant Date, cause shall mean continued failure to substantially perform the Participant’s duties or misconduct that is materially injurious to the Corporation.

          (c) If the Participant is terminated by the Corporation or any of its Affiliates without cause, or if the Participant elects to terminate employment with the Corporation or any of its Affiliates for Good Reason (as defined in an Employment Agreement dated on or before the Grant Date) the shares shall continue to vest, and the restrictions with respect to the shares shall lapse in installments on the dates and in the amounts set forth in the Restricted Stock Award Certificate for Employees.

     6. Restriction on Transfer. Until the Shares vest pursuant to Section 3, 4 or 5(a) hereof, none of the Shares may be sold, assigned, transferred, pledged, hypothecated or otherwise disposed of or encumbered, and no attempt to transfer the Shares, whether voluntary or involuntary, by operation of law or otherwise, shall vest the transferee with any interest or right in or with respect to the Shares.

     7. Issuance and Custody of Certificates.

          (a) The Corporation shall cause to be issued one or more stock certificates, registered in the Participant’s name, representing the Shares. Each such certificate shall be subject to an appropriate stop-transfer order and shall bear the following legend:

“The Common Shares represented by this certificate are subject to forfeiture, and the transferability of this certificate and the Common Shares represented hereby are subject to the restrictions, terms and conditions (including restrictions against transfer) contained in the Otter Tail Corporation 1999 Stock Incentive Plan and a Restricted Stock Award Agreement between Otter Tail Corporation and the registered owner of such shares. Release from such restrictions, terms and conditions shall be made only in accordance with the provisions of the Plan and the Agreement, copies of which are on file in the office of the Secretary of Otter Tail Corporation.”

3

          (b) Upon execution of this Agreement, the Participant shall execute and deliver to the Corporation a stock power or stock powers relating to the Shares.

          (c) Each certificate issued pursuant to Section 7(a) hereof, together with the stock power or stock powers relating to the Shares, shall be deposited by the Corporation with the Secretary of the Corporation or a custodian designated by the Secretary.

          (d) After any Shares vest pursuant to Section 3, 4 or 5(a) hereof, and following payment of the applicable withholding taxes pursuant to Section 9 hereof, the Corporation shall promptly cause to be issued a certificate or certificates, registered in the Participant’s name or in the name of the Participant’s legal representatives, beneficiaries or heirs, as the case may be, representing such vested Shares (less any shares withheld to pay withholding taxes), free of the legend provided in Section 7(a) hereof and any stop-transfer order with respect to such Shares, and shall cause such certificate or certificates to be delivered to the Participant or the Participant’s legal representatives, beneficiaries or heirs, as the case may be.

     8. Distributions and Adjustments.

          (a) If any Shares vest in the Participant subsequent to any change in the number or character of the Common Shares of the Corporation (through recapitalization, stock split, stock dividend, reorganization, merger, consolidation or otherwise), the Participant shall then receive upon such vesting the number and type of securities or other consideration which the Participant would have received if such Shares had vested prior to the event changing the number or character of the outstanding Common Shares.

          (b) Any additional Common Shares of the Corporation, any other securities of the Corporation and any other property (except for cash dividends or other cash distributions) distributed with respect to the Shares prior to the date or dates the Shares vest shall be subject to the same restrictions, terms and conditions as the Shares to which they relate and shall be promptly deposited with the Secretary of the Corporation or a custodian designated by the Secretary.

          (c) Any cash dividends or other cash distributions payable with respect to the Shares shall be distributed to the Participant at the same time cash dividends or other cash distributions are distributed to shareholders of the Corporation generally.

     9. Income Tax Matters.

          (a) The Participant acknowledges that the Participant will consult with the Participant’s personal tax advisor regarding the income tax consequences of the grant of the Shares, payment of dividends on the Shares and the vesting of the Shares or any other matters related to this Agreement. In order to comply with all applicable federal or state income tax laws or regulations, the Corporation may take such action as it deems appropriate to ensure that all applicable federal or state payroll, withholding, income or other taxes, which are the sole and absolute responsibility of the Participant, are withheld or collected from the Participant.

4

          (b) In accordance with the terms of the Plan, and such rules as may be adopted by the Committee under the Plan, the Participant may elect to satisfy the Participant’s federal and state income tax withholding obligations arising from the receipt of, or the lapse of restrictions relating to, the Shares by (i) delivering cash, check (bank check, certified check or personal check) or money order payable to the order of the Corporation, or (ii) having the Corporation withhold a portion of the Shares otherwise to be delivered having a Fair Market Value equal to the amount of such taxes. The Corporation will not deliver any fractional Share but will pay, in lieu thereof, the Fair Market Value of such fractional Share. The Participant’s election must be made on or before the date that the amount of tax to be withheld is determined.

     10. Miscellaneous.

          (a) Nothing contained in this Agreement or the Plan shall confer on the Participant any right to continue in the employ of the Corporation or any Affiliate or affect in any way the right of the Corporation or any Affiliate to terminate the employment of the Participant at any time.

          (b) The Corporation shall not be required to deliver any Shares until the requirements of any federal or state securities laws, rules or regulations or other laws or rules (including the rules of any securities exchange) as may be determined by the Corporation to be applicable are satisfied.

          (c) This Agreement is subject to the terms of the Plan. Terms used in this Agreement which are not defined herein shall have the respective meanings given to such terms in the Plan. A copy of the Plan is available to the Participant upon request.

          (d) This Agreement shall be governed by and construed in accordance with the internal laws of the State of Minnesota, without giving effect to the conflicts of laws principles thereof.

          (e) Headings in this Agreement are for convenience of reference only and shall not be deemed in any way to be material or relevant to the construction or interpretation of this Agreement or any provision hereof.

          (f) THIS RESTRICTED STOCK AWARD AGREEMENT FOR EMPLOYEES IS ATTACHED TO AND MADE A PART OF A RESTRICTED STOCK AWARD CERTIFICATE FOR EMPLOYEES AND SHALL HAVE NO FORCE OR EFFECT UNLESS SUCH RESTRICTED STOCK AWARD CERTIFICATE FOR EMPLOYEES IS DULY EXECUTED AND DELIVERED BY THE CORPORATION AND THE PARTICIPANT.

* * * * * * * *

5

OTTER TAIL CORPORATION
1999 STOCK INCENTIVE PLAN

RESTRICTED STOCK AWARD CERTIFICATE FOR EMPLOYEES

     This certifies the award of restricted stock as specified below which has been granted under the Otter Tail Corporation 1999 Stock Incentive Plan (the “Plan”), the terms and conditions of which are incorporated by reference herein and made a part hereof. In addition, the award shown in this Certificate is nontransferable and is subject to the terms and conditions set forth in the attached 2005 Restricted Stock Award Agreement for Employees of which this Certificate is a part.

[Name and address of recipient]

[Social Security Number of recipient]

You have been granted the following Award:

Grant Type:	Restricted Stock
Number of Common Shares:
Grant Date:	April 11, 2005
Vesting Schedule:

	Percentage of
Date	Restricted Stock Vested
April 8, 2006		25	%
April 8, 2007		25	%
April 8, 2008		25	%
April 8, 2009		25	%

     By the Corporation’s and your signature below, it is agreed that this award of restricted stock is governed by the terms and conditions of the 2005 Restricted Stock Award Agreement for Employees, a copy of which is attached and made a part of this document, and the Corporation’s 1999 Stock Incentive Plan, a copy of which is enclosed.

OTTER TAIL CORPORATION
By:
	John D. Erickson
	President and Chief Executive Officer
	[Name of recipient]

6

EX-13.A

Exhibit 13-A

Selected Consolidated Financial Data

(thousands, except number of shareholders and per-share data)	2005			2004			2003			2002			2001			2000			1995
Revenues
Electric	$	312,985		$	266,385		$	267,494		$	244,005		$	232,720		$	219,718		$	192,053
Plastics		158,548			115,426			86,009			82,931			63,216			82,667			4,569
Manufacturing (1)		244,311			201,615			157,401			119,880			96,571			73,940			34,121
Health services		123,991			114,318			100,912			93,420			79,129			66,319			50,896
Food Ingredient Processing		38,501			14,023			—			—			—			—			—
Other business operations (1)		171,939			148,328			114,726			75,947			72,191			70,145			28,984
Intersegment eliminations		(3,867	)		(2,733	)		(2,254	)		(1,036	)		—			—			—
Total operating revenues	$	1,046,408		$	857,362		$	724,288		$	615,147		$	543,827		$	512,789		$	310,623
Income from continuing operations (1)		52,855			40,632			38,225			44,222			40,055			37,654			28,305
Income from discontinued operations (1)		9,696			1,563			1,431			1,906			3,548			3,388			640
Net income		62,551			42,195			39,656			46,128			43,603			41,042			28,945
Operating cash flow from continuing operations (1)		90,358			54,330			76,314			71,582			71,025			57,110			56,404
Operating cash flow — continuing and discontinued operations		95,800			56,301			76,955			76,797			77,529			61,761			58,077
Capital expenditures — continuing operations (1)		59,969			49,484			48,783			73,447			50,727			44,655			36,343
Total assets		1,181,496			1,134,148			986,423			914,112			817,778			772,562			643,173
Long-term debt (1)		258,260			261,805			262,311			254,015			221,643			188,031			160,235
Redeemable preferred		—			—			—			—			—			18,000			18,000
Basic earnings per share — continuing operations (1) (2)		1.79			1.53			1.46			1.73			1.55			1.46			1.16
Basic earnings per share — total (2)		2.12			1.59			1.52			1.80			1.69			1.59			1.19
Diluted earnings per share — continuing operations (1) (2)		1.78			1.52			1.45			1.71			1.53			1.45			1.16
Diluted earnings per share — total (2)		2.11			1.58			1.51			1.79			1.68			1.59			1.19
Return on average common equity		13.9	%		12.0	%		12.2	%		15.3	%		15.5	%		15.4	%		14.8	%
Dividends per common share		1.12			1.10			1.08			1.06			1.04			1.02			0.88
Dividend payout ratio		53	%		70	%		72	%		59	%		62	%		64	%		74	%
Common shares outstanding — year end		29,401			28,977			25,724			25,592			24,653			24,574			22,360
Number of common shareholders (3)		14,801			14,889			14,723			14,503			14,358			14,103			13,933

Notes:
(1)	Prior years are restated to exclude the operations of Midwest Information Systems, Inc., St George Steel Fabrication, Inc. and Chassis Liner Corporation, which are classified as discontinued operations. See note 15 to consolidated financial statements.
(2)	Based on average number of shares outstanding.
(3)	Holders of record at year end.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

Otter Tail Corporation and our subsidiaries form a diverse group of businesses with operations classified into six segments: electric, plastics, manufacturing, health services, food ingredient processing and other business operations. Our primary financial goals are to maximize earnings and cash flows and to allocate capital profitably toward growth opportunities that will increase shareholder value. Meeting these objectives enables us to preserve and enhance our financial capability by maintaining desired capitalization ratios and a strong interest coverage position, and preserving solid credit ratings on outstanding securities, which, in the form of lower interest rates, benefits both our customers and shareholders.

Our vision is to create value and growth through ownership and acquisition of well-run companies in diverse businesses. Our strategy is straightforward: Reliable utility performance combined with growth opportunities at all our businesses provides long-term value. This includes growing our core electric utility business which provides a strong base of revenues, earnings and cash flows. In addition, we look to our 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. We adhere to strict guidelines when reviewing acquisition candidates since our 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, we also avoid concentrating business risk within a single industry. All our operating companies operate under a decentralized business model with disciplined corporate oversight.

We assess the performance of our operating companies over time, using the following criteria:

• ability to provide returns on invested capital that exceed our weighted average cost of capital over the long term; and

• assessment of an operating company’s business and potential for future earnings growth.

We are a committed long-term owner and therefore we do not acquire companies in pursuit of short-term gains. However, we will divest operating companies if they do not meet these criteria over the long term.

The following major events occurred in our company in 2005:

• Our annual consolidated revenues topped $1 billion for the first time in our history.

• We reported record consolidated earnings and record earnings in our electric and plastics segments.

• We sold three of our operating companies for a net after-tax gain of $10.0 million.

• In June we jointly announced an agreement with six other regional utilities to build a new 600-megawatt coal-fired electric generating plant (BSP II) on the site of the existing Big Stone Plant if all necessary permits and approvals are granted on a timely basis.

Major growth strategies and initiatives in our company’s future include:

• Planned capital budget expenditures of $477 million for the years 2006-2010, including $247 million related to BSP II, if built.

• The continued investigation and evaluation of strategic acquisition opportunities.

• Pursuing the regulatory approvals, financing and other arrangements necessary to build BSP II.

The following table summarizes our consolidated results of operations for the years ended December 31:

(in thousands)	2005		2004
Operating revenues:
Electric	$	312,985	$	266,385
Nonelectric		733,423		590,977
Total operating revenues	$	1,046,408	$	857,362
Net income from continuing operations:
Electric	$	37,301	$	31,535
Nonelectric		15,554		9,097
		52,855		40,632
Net income from discontinued operations		9,696		1,563
Total net income	$	62,551	$	42,195

The 22.0% increase in consolidated revenues in 2005 compared with 2004 reflects revenue growth in all our business segments. Revenues in the electric segment increased $46.6 million reflecting a $24.6 million increase in retail electric revenue, a $19.2 million increase in wholesale energy and mark-to-market revenues and a $2.8 million increase in other electric revenue. Revenues grew $43.1 million in our plastics segment in 2005 primarily as a result of rising resin prices and increased demand for polyvinyl chloride (PVC) pipe, particularly following the 2005 Gulf Coast hurricanes. Revenues increased $42.7 million in our manufacturing segment in 2005 as a result of increased unit sales and price increases related to increases in raw material costs, sales of higher priced products and the acquisitions of three companies in 2005. Revenues from our health services segment increased $9.7 million. Scanning and other related service revenues increased $13.9 million while revenues from equipment sales and service decreased $4.2 million between the years. Revenues in our food ingredient processing segment were $38.5 million for 2005 compared with $14.0 million from our 19 weeks of ownership in 2004. Other business operations revenue grew by $23.6 million with most of the increase coming from our energy services company as a result of higher natural gas prices in 2005.

A 93% increase in net margins from wholesale electric sales and energy trading activities and a 3.2% increase in retail electric megawatt-hour sales were the main contributing factors to the $5.8 million increase in electric segment net income. A record year in our plastics segment and an increase in earnings from continued improvements in our health services segment were the major factors contributing to the $6.5 million increase in net income from our nonelectric business segments in 2005 compared with 2004.

Following is a more detailed analysis of our operating results by business segment for the three years ended December 31, 2005, 2004 and 2003, followed by our outlook for 2006, a discussion of our financial position at the end of 2005 and risk factors that may affect our future operating results and financial position.

RESULTS OF OPERATIONS

This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes found elsewhere in this report. See note 2 to our consolidated financial statements for a complete description of our lines of business, locations of operations and principal products and services.

Amounts presented in the segment tables that follow for 2005, 2004 and 2003 operating revenues, cost of goods sold and other nonelectric operating expenses will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

(in thousands)	2005		2004		2003
Operating revenues	$	3,867	$	2,733	$	2,254
Cost of goods sold		2,070		1,083		527
Other nonelectric expenses		1,797		1,650		1,727

ELECTRIC

The following table summarizes the results of operations for our electric segment for the years ended December 31:

			%				%
(in thousands)	2005		change		2004		change		2003
Retail sales revenues	$	248,939		11	$	224,326		3	$	217,439
Wholesale revenues		41,953		75		24,000		(6)		25,644
Net marked-to-market gains		4,444		38		3,228		(20)		4,058
Other revenues		17,649		19		14,831		(27)		20,353
Total operating revenues	$	312,985		17	$	266,385		—	$	267,494
Production fuel		55,927		7		52,056		2		51,163
Purchased power – system use		58,828		47		40,098		11		36,002
Other operation and maintenance expenses		99,904		17		85,361		(2)		87,186
Depreciation and amortization		24,397		1		24,236		(7)		26,008
Property taxes		10,043		(4)		10,411		8		9,598
Operating income	$	63,886		18	$	54,223		(6)	$	57,537

The $24.6 million increase in retail revenues from 2004 to 2005 includes $16.0 million in increased fuel clause adjustment (FCA) revenues directly related to increases in fuel and purchased power costs in 2005 and $8.6 million from a 3.2% increase in retail kilowatt-hour (kwh) sales. Residential kwh sales increased 3.9% primarily due to an 86% increase in cooling degree-days in the summer of 2005 compared with the summer of 2004. Kwh sales to commercial and industrial customers increased 3.0% due to an improving regional economy.

Wholesale revenues increased $18.0 million in 2005 compared with 2004. 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 (FTRs). Virtual transactions are of two types: 1) A Virtual Demand Bid is a bid to purchase energy in MISO’s Day-Ahead Market that is not backed by physical load. 2) A Virtual Supply Offer 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. We recorded $12.7 million in net revenues related to virtual transactions in 2005. 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 FTRs can be granted 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. We recorded $1.9 million in net revenue related to bilateral trading of FTRs in MISO’s secondary market in 2005. In 2005, net revenues from the purchase and sale of electric energy contracts, including virtual transactions and FTRs, increased $11.2 million, compared with net revenues from energy trading activities in 2004, on a 178% increase in kwh volume traded between the years. As the MISO markets evolve and become more efficient, profits from virtual and FTR transactions may be reduced. Revenues from wholesale energy sales from company-owned generation increased $6.8 million due to a 58.9% increase in the average price per kwh sold in 2005 compared with 2004, offset by a 13.2% reduction in kwh sales. The increase in the average price per kwh is reflective of a general increase in energy prices in 2005 related to increased fuel costs.

The $1.2 million increase in net mark-to-market gains on forward energy contracts is due to an increase in the volume of forward energy contracts entered into in 2005 compared to 2004 combined with increasing energy prices in 2005. At December 31, 2005 the electric utility had recorded $2.9 million in net gains on forward energy contracts to be settled in 2006 compared with $0.3 million in recorded net gains on forward energy contracts at December 31, 2004 that were settled in 2005.

The $2.8 million increase in other electric revenues is related mostly to transmission studies completed by Otter Tail Power Company for MISO and transmission line permitting work done for other companies.

In December 2005, the Minnesota Public Utilities Commission (MPUC) issued an order denying the recovery of certain MISO-related costs through the 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 electric utility to reflect the refund obligation. On February 9, 2006 the MPUC reconsidered its December 2005 order. On reconsideration, the MPUC 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 possible recovery through base rates in the electric utility’s next general rate case. The MPUC’s final written order of this action is pending. When the final order is issued, the electric utility will recognize the $1.9 million in revenue and reverse the refund payable.

The $3.9 million increase in production fuel costs in 2005 compared with 2004 reflects a 15.5% increase in the cost of fuel per kwh generated, partially offset by a 7.0% reduction in generation. The decrease in kwhs generated is mainly due to the seven-week maintenance shutdown of Big Stone Plant in 2005. Fuel costs per kwh of generation increased at all three of our coal-fired generating plants as a result of increases in mine operating costs and, in the case of Hoot Lake and Big Stone Plants, increased costs for transporting coal by rail. Much of the increase in mine operating and coal transportation costs is directly related to a sharp increase in diesel fuel prices in 2005. Also, the overall increase in production fuel costs is partially attributable to our generation mix in 2005. Kwh generation at our higher-cost Hoot Lake generating units increased 25% in 2005 compared with 2004 while kwh generation at our lower-cost Big Stone and Coyote generating units decreased 21% and 6%, respectively, between the years. Fuel costs at our combustion turbine peaking plants increased $2.5 million (110%) while kwh generation increased by only 7.6%, reflecting increases in natural gas and fuel oil prices in 2005 and decreased plant efficiencies resulting from MISO dispatch directives.

Purchased power costs to serve retail customers increased $18.7 million as a result of a 28.2% increase in kwh purchases combined with a 14.5% increase in the cost per kwh purchased. Kwh purchases increased to make up for the shortfall caused by the Big Stone Plant shutdown and to provide for increased demand among retail electric customers. The increase in the cost per kwh of purchased power in 2005 is partially due to increases in fuel costs and partially due to a decrease in available electricity from hydro-generation in the region due to lower

water levels in Upper Missouri River reservoirs resulting from a prolonged drought in the Upper Missouri River basin. Approximately 90% of fuel and purchased power cost increases associated with service to retail electric customers is subject to recovery through the fuel cost recovery component of retail rates.

The $14.5 million increase in other operation and maintenance expenses in 2005 compared with 2004 includes increases of: $7.4 million in labor and benefits expense, $1.8 million in costs related to contract work performed for others, $1.5 million in storm damage repair costs, $1.3 million in tree-trimming and transmission line and pole maintenance expenditures and $1.1 million in maintenance expenses related to the seven-week maintenance shutdown of Big Stone Plant in 2005. The increase in labor and benefit expenses is due to wage and salary increases averaging 3.6%, and increases in pension costs, storm-related overtime pay, performance bonuses and safety awards.

The $0.4 million decrease in property taxes in 2005 compared with 2004 is a result of slightly lower utility property valuations in Minnesota in 2005.

The $6.9 million increase in retail revenues from 2003 to 2004 is mainly due to a $4.0 million increase in FCA revenues. The remaining increase in retail revenues was due to a 1.5% increase in retail kwh sales. The increase in retail sales reflects a 3.2% increase in kwh sales to commercial and industrial customers, partially offset by a 2.0% decrease in kwh sales to residential customers. The increase in commercial and industrial kwh sales reflects increased sales to pipeline customers related to increased oil prices and increased sales to large commercial customers due to a rebounding economy in 2004. Residential kwh sales decreased mainly as a result of a 55.7% decrease in cooling degree-days in the summer of 2004 compared with the summer of 2003. The increase in FCA revenues is due to a 16.3% increase in kwh purchases for retail use in 2004 compared with 2003. Fuel and purchased power costs for retail use also increased as a result of higher retail kwh demand in 2004 compared with 2003.

Wholesale revenues from sales of company-owned generation decreased $0.6 million in 2004 compared with 2003 due to a 1.9% decrease in kwh sales combined with a 1.5% decrease in revenue per kwh of generation sold. Fuel costs per kwh of generation used for wholesale sales decreased 2.6% between the years resulting in a decrease in the gross margin per kwh sold from company-owned generation of only 0.2%. Net margins on purchased power resold decreased $1.0 million despite a 2.2% increase in kwh sales as a result of a 16.3% decrease in the gross margin per kwh of purchased power resold. The 2003 mid-year change in the revenue recognition methodology (applied to resales of purchased power from contract-based prices to market-based prices as a result of adopting SFAS No. 133 in July 2003) is a contributing factor to the 16.3% decrease in the gross margin per kwh of purchased power resold between 2003 and 2004. The $0.8 million decrease in net mark-to-market gains on forward energy contracts reflects the recognition of $2.1 million in net gains related to the initial adoption of mark-to-market accounting on forward energy contracts in July 2003, partially offset by a $1.3 million increase in mark-to-market gains recognized in 2004 compared with 2003 as a result of applying mark-to-market accounting to forward energy contracts for all of 2004 compared with applying it for only six months of 2003.

In 2003, other electric operating revenues included revenues from contracted construction work completed on a large wind farm project in North Dakota. The electric utility did not have a construction contract of similar magnitude in 2004, which is the main reason for the $5.5 million reduction in other electric revenues between 2003 and 2004.

The $1.8 million decrease in other operation and maintenance expenses in 2004 compared with 2003 includes a $3.2 million reduction in costs related to contracted construction work on the wind farm project completed in 2003. This reduction was partially offset by increases in regulatory expenses and increases in expenses related to transmission services, and a $0.6 million net increase in labor and benefit expenses after taking into account a $0.7 million reduction in retiree medical benefit costs related to the Medicare prescription drug benefit subsidy recorded in 2004.

The $1.8 million decrease in depreciation and amortization expense for 2004 compared with 2003 is related to the extension of the depreciable service lives of certain units of electric utility property. The extension of these depreciable service lives was included in the electric utility’s annual depreciation study and depreciation rates approved by the MPUC. The $0.8 million increase in property taxes in 2004 compared with 2003 is mainly related to a 9.0% increase in the value of electric utility property apportioned to Minnesota related to the value the State of Minnesota assigned to the utility’s Solway combustion turbine generator property.

PLASTICS

The following table summarizes the results of operations for our plastics segment for the years ended December 31:

			%				%
(in thousands)	2005		change		2004		change		2003
Operating revenues	$	158,548		37	$	115,426		34	$	86,009
Cost of goods sold		121,245		25		97,126		28		76,046
Operating expenses		10,939		91		5,718		50		3,824
Depreciation and amortization		2,511		9		2,297		8		2,126
Operating income	$	23,853		132	$	10,285		156	$	4,013

The $43.1 million increase in plastics operating revenues in 2005 compared with 2004 reflects a 31.9% increase in the average sales price per pound of PVC pipe sold combined with a 3.2% increase in pounds of PVC pipe sold between the years. The increase in revenue reflects the effect of rising resin prices and increased customer demand for PVC pipe. Demand accelerated to record levels late in the third quarter of 2005 as substantial resin price increases were announced and concerns developed over the adequacy of resin supply following the 2005 Gulf Coast hurricanes. A majority of U.S. resin production plants are located in the Gulf Coast region. The increase in revenues was partially offset by a $24.1 million increase in cost of goods sold, reflecting a 19.9% increase in the average cost per pound of pipe sold. The average cost per pound of resin, the raw material used to produce PVC pipe, increased 16.4% between the periods. The $5.2 million increase in operating expenses between the periods primarily is due to increases in costs directly related to increased sales. The increase in depreciation and amortization expense relates mostly to manufacturing equipment purchased in 2004 and 2005.

The $29.4 million increase in plastics operating revenues in 2004 compared with 2003 reflects a 10.8% increase in the pounds of PVC pipe sold between the years combined with an 18.2% increase in the average sales price per pound of pipe sold. The increase in revenues was partially offset by a $21.1 million increase in cost of goods sold reflecting an 11.7% increase in the average cost per pound of pipe sold. The average cost per pound of resin increased 19.0% between the periods. The $1.9 million increase in operating expenses between the periods primarily is due to increases in costs directly related to increased sales along with increases in building rental expenses and property taxes related to our polyethylene pipe plant in Hampton, Iowa, which began operations in summer 2003. The increase in depreciation and amortization expense relates mostly to manufacturing equipment purchased in 2003 and 2004.

MANUFACTURING

Operating results for the manufacturing segment for 2004 and 2003 have changed as a result of the reclassification of St. George Steel Fabrication, Inc. and Chassis Liner Corporation to discontinued operations in 2005. The following table summarizes the results of operations for our manufacturing segment for the years ended December 31:

			%				%
(in thousands)	2005		change		2004		change		2003
Operating revenues	$	244,311		21	$	201,615		28	$	157,401
Cost of goods sold		194,264		23		157,802		29		122,763
Operating expenses		23,872		13		21,098		14		18,471
Depreciation and amortization		9,447		21		7,828		14		6,882
Operating income	$	16,728		12	$	14,887		60	$	9,285

Revenue increases at the manufacturing companies in 2005 compared with 2004 are due to a combination of factors including increased unit sales, increased sales of higher-priced products, higher prices related to material cost increases and 2005 acquisitions. The increase in cost of goods sold in the manufacturing segment was proportional to the increase in sales revenue resulting in a $6.2 million increase in manufacturing segment gross profits between the periods.

The increase in revenues in our manufacturing segment in 2005 compared with 2004 relates to the following:

• Revenues at DMI Industries, Inc. (DMI), our manufacturer of wind towers, increased $23.8 million (48.9%) due to increased production and sales activity. This is in part related to the production tax credits for wind-generated electricity being in place for 2005 as well as improvements in productivity and capacity utilization.

• Revenues at BTD Manufacturing Inc. (BTD), our metal parts stamping and fabrication company, increased $10.2 million (14.9%) mainly as a result of product price increases to cover rising material costs reflected in an 11.8% increase in revenue per unit sold between the periods. The purchase of Performance Tool in January 2005 contributed $3.8 million toward BTD’s revenue increase.

• Revenues at ShoreMaster, Inc., our waterfront equipment manufacturer, increased $4.9 million (9.5%) due to the acquisitions of Shoreline Industries and Southeast Floating Docks, offset in part by a decline in revenues in its residential and commercial divisions.

• Revenues at T.O. Plastics, Inc., our manufacturer of thermoformed plastic and horticultural products, increased $3.8 million (11.6%) as a result of productivity improvements and higher prices that provided for recovery of increased raw material costs.

The increase in cost of goods sold in our manufacturing segment in 2005 compared with 2004 relates to the following:

• DMI cost of goods sold increased $18.4 million between the periods as a result of increased production and higher raw material costs, subcontractor and labor costs. DMI cost of goods sold also includes a $1.0 million write-down of inventory in the third quarter 2005 for tower sections that have limited use in the wind business due to changes in wind tower design requirements.

• Cost of goods sold at BTD increased $12.1 million as a result of higher raw material and labor costs mainly related to increased production. The purchase of Performance Tool in January 2005 contributed $2.8 million toward BTD’s increase in cost of goods sold.

• ShoreMaster’s $3.8 million increase in cost of goods sold is mainly related to the acquisitions of Shoreline Industries and Southeast Floating Docks and increases in material costs.

• T.O. Plastics cost of goods sold increased $2.3 million between the periods as a result of increased material costs.

The increase in operating expenses in our manufacturing segment in 2005 compared with 2004 relates to the following:

• DMI operating expenses increased $1.2 million as a result of a $0.5 million increase in wages, salaries and benefit expenses, a $0.4 million increase in costs associated with changes in plant layout to improve productivity and a $0.2 million increase in repairs and maintenance costs.

• ShoreMaster’s operating expenses increased $1.5 million mainly as a result of the acquisitions of Shoreline Industries and Southeast Floating Docks in January and May of 2005.

Depreciation expense increased in 2005 compared with 2004 as a result of 2004 equipment additions and the 2005 manufacturing segment acquisitions.

The manufacturing segment’s improved performance in 2004 compared with 2003 can be attributed to certain companies within this segment being able to offset increases in commodity prices with product pricing increases and increased productivity and capacity utilization. The increases in productivity at BTD and DMI resulted in a combined increase in manufacturing segment operating income from these two companies of $6.5 million in 2004 compared with 2003. Revenue increases at the other manufacturing companies were offset by increased costs and operating expenses resulting in a combined net decrease in operating income from these companies of $0.9 million in 2004 compared with 2003.

The increase in revenues in our manufacturing segment in 2004 compared with 2003 relates to the following:

• Revenues at BTD increased $18.5 million (36.8%) as a result of product price increases related to increases in raw material costs, especially steel, and a 12.7% increase in the number of units produced and sold at BTD’s expanded manufacturing facilities in 2004 compared with 2003.

• DMI revenues increased $11.3 million (30.4%) reflecting product price increases related to increased steel prices and increased productivity and plant utilization in 2004.

• ShoreMaster revenues increased $8.6 million (19.7%) as a result of increases in sales of residential waterfront equipment, increases in jobs in progress and product price increases related to higher raw material costs.

• Revenues at T.O. Plastics increased $5.8 million (21.8%) as a result of a 14.2% increase in units sold in 2004 compared with 2003.

The $35.0 million increase in cost of goods sold in 2004 compared with 2003 includes increases of $13.3 million at BTD, $8.8 million at ShoreMaster, $7.7 million at DMI and $5.2 million at T.O. Plastics as a result of production increases and higher raw material costs at each of the companies.

The $2.6 million net increase in manufacturing segment operating expenses in 2004 compared with 2003 includes $1.9 million in increased expenses at BTD (reflecting increases in compensation and promotional expenses related to increased sales and losses related to the disposal of equipment no longer used in production) and $0.9 million in increased sales commissions at ShoreMaster. The $0.9 million increase in depreciation and amortization expense in 2004 compared with 2003 is mainly due to 2004 and 2003 equipment purchases at three of our manufacturing companies.

HEALTH SERVICES

The following table summarizes the results of operations for our health services segment for the years ended December 31:

			%				%
(in thousands)	2005		change		2004		change		2003
Operating revenues	$	123,991		8	$	114,318		13	$	100,912
Cost of goods sold		90,327		5		85,731		14		75,117
Operating expenses		21,989		25		17,593		14		15,410
Depreciation and amortization		4,038		(20)		5,047		(2)		5,137
Operating income	$	7,637		28	$	5,947		13	$	5,248

The $9.7 million increase in health services operating revenues for 2005 compared with 2004 reflects an increase of $13.9 million in scanning and other related service revenues offset by a decline in revenues from equipment sales and service of $4.2 million between the periods. The revenue per scan and the number of scans completed increased 9.6% and 5.9%, respectively. The imaging business added to its fleet of medical imaging equipment in 2005 resulting in an increase in revenue from rentals and interim installations of scanning equipment and related technical support services. The increase in health services revenue was partially offset by increases in cost of goods sold and operating expenses of $9.0 million to support the increases in imaging services activity. The increase in cost of goods sold is mainly related to increased equipment rental costs and increased labor costs partially offset by decreases in materials and maintenance costs. The increase in operating expenses is mainly due to increased payroll and travel expenses and increases in contractual allowances and bad debt expense between the periods and losses on equipment sales in 2005. The decrease in depreciation and amortization expense is the result of certain assets reaching the ends of their depreciable lives. When these assets are replaced, they are generally replaced with assets leased under operating leases. Improved operating efficiencies in the imaging business and service cost reductions initiated in 2004 along with growing scan counts have contributed to improved results in the health services segment.

The $13.4 million increase in health services operating revenues for 2004 compared with 2003 reflects $6.9 million in additional imaging revenues and $6.5 million from sales and servicing of equipment. The number of scans performed on a fee-per-scan basis decreased 14.1% while the average fee per scan increased 17.7%. The increase in revenue from equipment sales includes $1.8 million in increased revenue related to the acquisitions of Topline Medical and North Star Medical Systems in May and July of 2003. The $10.6 million increase in cost of goods sold in 2004 compared with 2003 includes $4.5 million related to equipment sales and $6.1 million related to imaging and other services. The $2.2 million increase in operating expenses reflects increases in compensation and benefits expenses and increases in travel expenses related to the 2003 medical equipment company acquisitions and an expansion of imaging services.

FOOD INGREDIENT PROCESSING

The following table summarizes the results of operations for our food ingredient processing segment for the periods ended December 31:

	2005		2004
(in thousands)	(full year)		(19 weeks)
Operating revenues	$	38,501	$	14,023
Cost of goods sold		30,930		11,379
Operating expenses		2,533		876
Depreciation and amortization		3,399		1,118
Operating income	$	1,639	$	650

The increases in revenues, cost of goods sold, operating expenses and depreciation and amortization are due to 2004 results reflecting only 19 weeks of operating activity as a result of the acquisition of Idaho Pacific Holdings, Inc. (IPH) in August 2004. Disclosure of pro forma information related to the results of operations of IPH for the periods presented in this report is not required due to immateriality.

Consistent with trends in the industry, operating income for 2005 was less than expected as a result of lower sales volume and prices, high energy costs, increasing raw material costs and the increasing value of the Canadian dollar relative to the U.S. dollar.

OTHER BUSINESS OPERATIONS

The following table summarizes the results of operations for our other business operations segment for the years ended December 31:

				%					%
(in thousands)	2005			change		2004			change		2003
Operating revenues	$	171,939			16	$	148,328			29	$	114,726
Cost of goods sold		131,951			17		113,054			37		82,378
Operating expenses		52,468			22		42,907			17		36,646
Goodwill impairment loss		1,003			—		—			—		—
Depreciation and amortization		2,666			(9)		2,945			4		2,841
Operating (loss)	$	(16,149	)		(53)	$	(10,578	)		(48)	$	(7,139	)

The increases in operating revenues and cost of goods sold in our other business operations in 2005 compared with 2004 are due to the following:

• Revenues at OTESCO, our energy services company, increased $20.4 million (45.8%), which includes $20.9 million in increased revenue from natural gas sales mainly as a result of increases in natural gas prices between the periods. The increase in revenue from natural gas sales was almost entirely offset by a $20.6 million increase in natural gas costs between the years. OTESCO also recorded a net increase in technical services revenue of $0.2 million between the years and a net loss on natural gas forward swap transactions of $0.5 million in 2005 compared to a net gain of $0.2 million recorded in 2004.

• Revenues at Midwest Construction Services, Inc. (MCS), our electrical design and construction services company, increased $16.6 million (61.4%) between the years as a result of an increase in work in progress, which was mostly offset by a $13.7 million increase in cost of goods sold including $4.4 million in increased material and labor costs incurred on a single project that resulted in a significant loss on that project.

• Revenues at E.W. Wylie Corporation (Wylie), our flatbed trucking company, increased $3.7 million (13.7%) in 2005 compared with 2004 due to a 9.7% increase in miles driven by company-operated and owner-operated trucks and a $0.9 million increase in fuel surcharge revenue.

• Revenues at Foley Company, a mechanical and prime contractor on industrial projects, decreased $17.2 million (35.4%) in 2005 compared with 2004 due to a decrease in jobs in progress. The decrease in Foley’s revenues was mostly offset by a decrease of $15.4 million in material, subcontractor, labor and insurance costs between the periods.

The increase in operating expenses in our other business operations segment in 2005 compared with 2004 relates to the following:

• Wylie’s operating expenses increased $3.9 million as a result of higher fuel prices, increased fuel usage and labor costs related to the increase in miles driven and increases in truck leasing costs between the periods.

• Increases in employee health insurance and other employee benefit costs and increases in insurance costs at our captive insurance company contributed $1.9 million to the increase in net losses in this segment.

• MCS reported increased expenses of $0.8 million for wages and benefits, outside contracted services and advertising and promotions in 2005 compared with 2004.

The $1.0 million goodwill impairment loss in 2005 relates to the write-off of goodwill at OTESCO in the third quarter of 2005 as a result of a reassessment of its future cash flows in light of rising natural gas prices and greater market volatility in future prices for natural gas.

Wylie’s depreciation and amortization expenses decreased by $0.3 million between the periods as a result of a 2004 decision to lease rather than buy replacement trucks for their fleet.

The increases in operating revenues and cost of goods sold in our other business operations in 2004 compared with 2003 are due to the following:

• Revenues at Foley Company, acquired in November 2003, increased $40.6 million and Foley’s cost of goods sold increased $36.7 million between the years, reflecting a full year of operations in 2004.

• Revenues at OTESCO increased $8.6 million (23.9%) and its cost of goods sold increased $8.5 million between the years mainly due to increases in natural gas prices.

• Wylie’s revenues increased $1.9 million (7.8%) reflecting increased brokerage activity and the pass through of increased diesel fuel prices to customers. Brokered miles increased 5.5% between the years while the combined miles driven by company-owned trucks and owner-operated trucks decreased 7.4%.

• MCS revenues decreased $17.7 million (39.5%) and cost of goods sold decreased $14.6 million between the periods due to a lower volume of available work in combination with excess capacity in MCS’s construction market.

The increase in operating expenses in our other business operations segment in 2004 compared with 2003 relates to the following:

• Foley’s operating expenses were $3.2 million for 2004 compared with $0.5 million for two months of operations in 2003.

• Wylie’s operating expenses increased $1.9 million mainly as a result of higher fuel prices and increased brokerage activity between the periods.

• Operating expenses in 2004 reflect $1.3 million in increased unallocated corporate overhead costs mainly due to increases in employee benefit costs and increased expenses for professional services related to compliance with Sarbanes-Oxley Section 404 requirements.

• MCS reported increased expenses of $0.7 million, mostly due to increases in payroll and advertising and promotional expenses in 2004 compared with 2003.

• OTESCO’s general and administrative expenses decreased $0.3 million between the years.

CONSOLIDATED INTEREST CHARGES

Interest expense increased $0.4 million in 2005 compared to 2004 primarily as a result of increased interest rates on short-term debt. In 2005, short-term debt interest expense was $1.6 million at an average rate of 3.7% on an average daily balance of $42.6 million, compared with $1.2 million at an average rate of 2.2% on an average daily balance of $57.8 million in 2004.

Interest expense increased $0.5 million in 2004 compared to 2003 primarily as a result of interest expense on the bridge loan used to finance the acquisition of IPH.

CONSOLIDATED INCOME TAXES

The 60% increase in income tax expense from continuing operations in 2005 compared to 2004 is due, in part, to a 39% increase in income from continuing operations before income taxes. Our effective tax rate on income from continuing operations was 34.6% for 2005 compared with 30.0% for 2004. The difference in the effective tax rate for 2005 compared to 2004 is a function of the level of fixed deductions and credits in proportion to higher net income before tax in 2005 compared to 2004. See note 14 to consolidated financial statements.

Our effective tax rate on income from continuing operations was 30.0% for 2004 compared with 27.0% for 2003. Approximately 1.0% of the difference in the effective tax rate for 2004 compared to 2003 reflects the impact of R&D tax credits claimed in 2003. The remaining 2.0% difference in the effective tax rate for 2004 compared to 2003 is a function of the level of fixed deductions and credits in proportion to higher net income before tax in 2004 compared to 2003.

DISCONTINUED OPERATIONS

Discontinued operations includes the operating results of Midwest Information Systems (MIS), a telecommunications company located in Parkers Prairie, Minnesota, St. George Steel Fabrication, Inc. (SGS), a structural steel fabricator located in St. George, Utah, and Chassis Liner Corporation (CLC) a manufacturer of auto and truck frame-straightening equipment and accessories located in Alexandria, Minnesota. The sales of MIS and SGS were completed in the second quarter of 2005. The sale of CLC was completed in the fourth

quarter of 2005. The following table presents operating revenues, expenses, including interest and other income and deductions, and income taxes, included on a net basis in income from discontinued operations on our 2005, 2004 and 2003 consolidated statements of income.

				%				%
(in thousands)	2005			change		2004		change		2003
Operating revenues	$	16,449			(51)	$	33,701		16	$	28,951
Expenses		16,978			(45)		31,098		16		26,752
Income tax (benefit) expense		(221	)		—		1,040		35		768
(Loss) income from discontinued operations	$	(308	)		—	$	1,563		9	$	1,431

The following table presents the pre-tax and net-of-tax gains and losses recorded on the sales of the three companies in 2005.

(in thousands)	MIS			SGS			CLC			Total
Gain (loss) on sale	$	19,025		$	(2,919	)	$	(271	)	$	15,835
Income tax (expense) benefit		(7,107	)		1,168			108			(5,831	)
Net gain (loss) on sale	$	11,918		$	(1,751	)	$	(163	)	$	10,004

IMPACT OF INFLATION

The electric utility operates under regulatory provisions that allow price changes in fuel and certain purchased power costs to be passed to most retail customers through automatic adjustments to its rate schedules under fuel clause adjustments. Other increases in the cost of electric service must be recovered through timely filings for electric rate increases with the appropriate regulatory agency.

Our plastics, manufacturing, health services, food ingredient processing, and other business operations consist entirely of unregulated businesses. Increased operating costs are reflected in product or services pricing with any limitations on price increases determined by the marketplace. Raw material costs, labor costs and interest rates are important components of costs for companies in these segments. Any or all of these components could be impacted by inflation or other pricing pressures, with a possible adverse effect on our profitability, especially where increases in these costs exceed price increases on finished products. In recent years, our operating companies have faced strong inflationary and other pricing pressures with respect to steel, fuel, resin, lumber, concrete, aluminum and health care costs, which have been partially mitigated by pricing adjustments.

2006 EXPECTATIONS

We anticipate 2006 diluted earnings per share from continuing operations will be in a range from $1.60 to $1.80. Contributing to the earnings expectations for 2006 are the following items:

• We expect solid performance in the electric segment in 2006 although net income is anticipated to be lower than 2005 levels. This is primarily because margins on wholesale electric sales are expected to be tighter as the MISO market becomes more efficient, anticipated increases in transmission service and wage and benefit costs, and uncertainty related to the recoverability of certain MISO-related costs through the fuel clause adjustments in Minnesota and North Dakota retail rates. We expect earnings for the electric segment in 2006 to return to more historical levels.

• We expect the plastics segment performance to return to more historical levels in 2006 following the 2005 record year.

• The improving economy, continued enhancements in productivity and capacity utilization, expanded markets, expansion of production capacity with the opening of a new wind tower production facility in Fort Erie, Ontario, Canada, and continued availability of production tax credits are expected to result in increased net income in our manufacturing segment.

• Our health services segment is expected to have moderate growth in net income in 2006.

• We expect our food ingredient processing business to generate net income in the range of $2 million to $4 million for the year ending December 31, 2006.

• Our other business operations segment is expected to show improved results over 2005 due to an improving economy and an increase in its backlog of construction contracts. An increase in wind energy projects activity is expected to have a positive impact on our electrical contracting business.

• We anticipate investing approximately $57 million in capital expenditures during 2006 in addition to funding possible future acquisitions.

• Our outlook for 2006 reflects the impact of Statement of Financial Accounting Standards No. 123(R), Share-Based Payment, which is anticipated to lower diluted earnings per share results by $0.015 per share in 2006. This standard requires all share-based compensation awards be measured at fair value at the date of grant and expensed over their vesting or service periods. This standard is effective beginning in January 2006.

Our outlook for 2006 is dependent on a variety of factors and is subject to the risks and uncertainties discussed under “Risk Factors and Cautionary Statements.”

LIQUIDITY

We believe our financial condition is strong and that our cash, other liquid assets, operating cash flows, access to capital markets through our universal shelf registration and borrowing ability because of solid credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. However, our operating cash flow and access to capital markets can be impacted by macroeconomic factors outside our control. In addition, our borrowing costs can be impacted by short-term and long-term debt ratings assigned to us by independent rating agencies, which in part are based on certain credit measures such as interest coverage and leverage ratios.

We have achieved a high degree of long-term liquidity by maintaining desired capitalization ratios and solid credit ratings, implementing cost-containment programs and investing in projects that provide returns in excess of our weighted average cost of capital.

Cash provided by operating activities from continuing and discontinued operations was $95.8 million in 2005 compared with $56.3 million in 2004. The $39.5 million increase in cash from operations reflects a $13.3 million increase in net income (net of the $3.0 million increase in noncash depreciation and amortization expense and excluding the $10.0 million gain on the sale of discontinued operations) and a $34.3 million increase in payables

and other current liabilities offset by a $7.8 million increase in receivables, inventories and other current assets between the years. The increase in payables and other current liabilities includes: $11.5 million related to PVC resin purchased in the fourth quarter of 2005 under extended payment terms related to a normal slowdown in business in the fourth quarter, $6.5 million in incentive compensation accrual increases related to improved results in the electric and plastics business segments in 2005 and increased production activity at DMI, $5.4 million in billings in excess of costs at DMI and Shoremaster related to an increase in jobs in progress at year-end 2005 compared with year-end 2004, a $4.7 million increase in accounts payable at DMI related to a large steel shipment received in December 2005, a $1.9 million refund payable related to a MPUC order in December 2005, and an increase of $3.4 million in deposits, deferred revenues and business insurance reserves at year-end 2005 compared to year-end 2004. The increase in receivables and inventories reflects increases in receivables, mainly at MCS and the plastic pipe companies and increases in inventories primarily at the manufacturing companies. While consolidated accounts receivables are higher at December 31, 2005 compared with December 31, 2004, the average days outstanding for accounts receivable decreased between the years.

The $91.1 million decrease in net cash used in investing activities in 2005 compared with 2004 reflects a $57.8 million decrease in cash used to complete acquisitions and $34.2 million in proceeds from the sales of MIS, SGS and CLC in 2005. The decrease in cash used for acquisitions and other investments is mostly related to the 2004 acquisition of IPH, in which $68.2 million in cash was paid and $6.0 million was placed in escrow to pay off earn-out contingencies if IPH achieved certain financial targets for the period from August 1, 2004 through July 31, 2005. The financial targets were not achieved and the $6.0 million in escrow was returned to the Company in August 2005, contributing to cash flows from other investments in 2005. A breakdown of capital expenditures by segment is provided below under Capital Requirements.

Cash paid for acquisitions in 2005 net of cash acquired included the following:

Company	(thousands)
Performance Tool	$	4,116
Shoreline Industries		2,328
Southeast Floating Docks		3,968
Contingency payments—prior years’ acquisitions		811
Total	$	11,223

Net cash used in financing activities was $62.0 million in 2005 compared with net cash provided by financing activities of $55.9 million in 2004. Major uses of cash for financing activities in 2005 were:

• $32.7 million for the payment of dividends on common shares outstanding

• $24.0 million for repayment of short-term debt

• $7.2 million for the retirement of long-term debt

The $9.7 million in net proceeds from the issuance of common stock in 2005 included $5.8 million from the exercise of stock options and $4.3 million from the issuance of 175,000 common shares in January 2005 as a result of the underwriters exercising a portion of their over-allotment option in connection with our December 2004 public offering.

CAPITAL REQUIREMENTS

We have a capital expenditure program for the expansion, upgrade and improvement of our plants and operating equipment. Typical uses of cash for capital expenditures are investments in electric generation facilities, transmission and distribution lines, equipment used in the manufacturing process, purchase of diagnostic medical equipment, transportation equipment and computer hardware and information systems. The capital expenditure program is subject to review and is revised annually in light of changes in demands for energy, technology, environmental laws, regulatory changes, business expansion opportunities, the costs of labor, materials and equipment and our consolidated financial condition.

Consolidated capital expenditures for the years 2005, 2004 and 2003 were $60.0 million, $49.5 million and $48.8 million, respectively. The estimated capital expenditures for 2006 are $57.4 million and the total capital expenditures for the five-year period 2006 through 2010 are estimated to be approximately $477 million, which includes $247 million for our share of expected expenditures for construction of the planned BSP II electric generating plant and related transmission assets if all necessary permits and approvals are granted on a timely basis.

The breakdown of 2003, 2004 and 2005 actual and 2006 through 2010 estimated capital expenditures by segment is as follows:

(in millions)	2003		2004		2005		2006		2006-2010
Electric	$	28	$	25	$	30	$	29	$	381
Plastics		4		3		4		8		18
Manufacturing		10		13		16		13		55
Health services		6		4		3		1		3
Food ingredient processing		—		4		3		4		15
Other business operations		1		1		4		2		5
Total	$	49	$	50	$	60	$	57	$	477

The following table summarizes our contractual obligations at December 31, 2005 and the effect these obligations are expected to have on our liquidity and cash flow in future periods.

			Less than		1-3		3-5		More than
(in millions)	Total		1 year		years		years		5 years
Long-term debt obligations	$	262	$	3	$	58	$	5	$	196
Interest on long-term debt obligations		141		16		27		24		74
Operating lease obligations		136		37		59		37		3
Capacity and energy requirements		110		17		33		24		36
Coal contracts (required minimums)		84		16		22		12		34
Postretirement benefit obligations		47		4		7		8		28
Other purchase obligations		42		42		—		—		—
Total contractual cash obligations	$	822	$	135	$	206	$	110	$	371

Interest on $22.0 million of variable-rate debt outstanding on December 31, 2005 was projected based on the interest rates applicable to those debt instruments on December 31, 2005.

CAPITAL RESOURCES

Financial flexibility is provided by operating cash flows, our universal shelf registration, unused lines of credit, strong financial coverages, solid credit ratings, and alternative financing arrangements such as leasing. We have the ability to issue up to $256 million of common stock, preferred stock, debt and certain other securities from time to time under our universal shelf registration statement filed with the Securities and Exchange Commission. Additional equity or debt financing may be required in the period 2006 through 2010 in the event we decide to refund or retire early any of our presently outstanding debt or cumulative preferred shares, to retire the $50 million 6.375% senior debentures due December 1, 2007, to complete acquisitions, to fund the construction of the new BSP II generating station at the Big Stone Plant site or for other corporate purposes. There can be no assurance that any additional required financing will be available through bank borrowings, debt or equity financing or otherwise, or that if such financing is available, it will be available on terms acceptable to us. If adequate funds are not available on acceptable terms, our businesses, results of operations and financial condition could be adversely affected.

Our $100 million line of credit with U.S. Bank National Association, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, and Bank Hapoalim B.M., expires on April 26, 2006. The terms of the current line of credit are essentially the same as those in place in the prior agreement. However, outstanding letters of credit issued by the company can reduce the amount available for borrowing under the line by up to $20 million. Borrowings under the line of credit bear interest at LIBOR plus 0.6%, subject to adjustment based on the ratings of our senior unsecured debt. We do not anticipate any difficulties in renewing this line of credit.

Our bank line of credit is a key source of operating capital and can provide interim financing of working capital and other capital requirements, if needed. This line is an unsecured revolving credit facility available to support borrowings of our nonelectric operations. We anticipate that the electric utility’s cash requirements will be provided for by cash flows from electric utility operations. Our obligations under this line of credit are guaranteed by our 100%-owned subsidiary that owns substantially all of our nonelectric companies. As of December 31, 2005, $16.0 million of the $100 million line of credit was in use and $12.0 million was restricted from use to cover outstanding letters of credit.

Our line of credit, $90 million 6.63% senior notes and Lombard US Equipment Finance note contain the following covenants: a debt-to-total capitalization ratio not in excess of 60% and an interest and dividend coverage ratio of at least 1.5 to 1. The 6.63% senior notes also require that priority debt not be in excess of 20% of total capitalization. We were in compliance with all of the covenants under our financing agreements as of December 31, 2005.

Our obligations under the 6.63% senior notes are guaranteed by our 100%-owned subsidiary that owns substantially all of our nonelectric companies. Our Grant County and Mercer County pollution control refunding revenue bonds require that we grant to Ambac Assurance Corporation, under a financial guaranty insurance policy relating to the bonds, a security interest in the assets of the electric utility if the rating on our senior unsecured debt is downgraded to Baa2 or below (Moody’s) or BBB or below (Standard & Poor’s).

On August 26, 2005 Moody’s Investor Service lowered its ratings of our senior unsecured debt from A2 to A3 and our preferred stock from Baa1 to Baa2 and changed its outlook from negative to stable. On December 22, 2005 Standard & Poor’s Rating Services affirmed our corporate credit rating and senior unsecured debt rating of BBB+. At the same time the outlook was revised from negative to stable.

Our securities ratings at December 31, 2005 are:

	Moody’s
	Investors		Standard
	Service		& Poor’s
Senior unsecured debt		A3	BBB+
Preferred stock	Baa2		BBB–
Outlook	Stable		Stable

Disclosure of these securities ratings is not a recommendation to buy, sell or hold our securities. Downgrades in these securities ratings could adversely affect our company. Further downgrades could increase borrowing costs resulting in possible reductions to net income in future periods and increase the risk of default on our debt obligations.

Our ratio of earnings to fixed charges from continuing operations, which includes imputed finance costs on operating leases, was 4.3x for 2005 compared to 3.4x for 2004 and our long-term debt interest coverage ratio before taxes was 6.3x for 2005 compared to 4.9x for 2004. During 2006, we expect these coverage ratios to decrease from 2005 levels assuming 2006 net income meets our expectations.

OFF-BALANCE-SHEET ARRANGEMENTS

We do not have any off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.

RISK FACTORS AND CAUTIONARY STATEMENTS

We are including the following factors and cautionary statements in this Annual Report to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by us or on our behalf. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are other than statements of

historical facts. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All these forward-looking statements, whether written or oral and whether made by us or on our behalf, are also expressly qualified by these factors and cautionary statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of the factors, nor can we assess the effect of each factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The following factors and the other matters discussed herein are important factors that could cause actual results or outcomes for our company to differ materially from those discussed in the forward-looking statements included elsewhere in this document.

GENERAL

Our plans to grow and diversify through capital expenditures and acquisitions may not be successful, which could result in poor financial performance.

As part of our business strategy, we intend to acquire new businesses. We may not be able to identify appropriate acquisition candidates or successfully negotiate, finance or integrate acquisitions. If we are unable to make acquisitions, we may be unable to realize the growth we anticipate. Future acquisitions could involve numerous risks including: difficulties in integrating the operations, services, products and personnel of the acquired business; and the potential loss of key employees, customers and suppliers of the acquired business. If we are unable to successfully manage these risks of an acquisition, we could face reductions in net income in future periods.

Federal and state environmental regulation could require us to incur substantial capital expenditures which could result in increased operating costs.

We are subject to federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources and health safety. These laws and regulations regulate the modification and operation of existing facilities, the construction and operation of new facilities and the proper storage, handling, cleanup and disposal of hazardous waste and toxic substances. Compliance with these legal requirements requires us to commit significant resources and funds toward environmental monitoring, installation and operation of pollution control equipment, payment of emission fees and securing environmental permits. Obtaining environmental permits can entail significant expense and cause substantial construction delays. Failure to comply with environmental laws and regulations, even if caused by factors beyond our control, may result in civil or criminal liabilities, penalties and fines.

Existing environmental laws or regulations may be revised and new laws or regulations may be adopted or become applicable to us. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material effect on our results of operations.

Volatile financial markets could restrict our ability to access capital and increase our borrowing costs and pension plan expenses.

We rely on access to both short- and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations. If we are not able to access capital at competitive rates, the ability to implement our business plans may be adversely affected. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or adversely affect our ability to access one or more financial markets.

Changes in the U.S. capital markets could also have significant effects on our pension plan. Our pension income or expense is affected by factors including the market performance of the assets in the master pension trust maintained for the pension plans for some of our employees, the weighted average asset allocation and long-term rate of return of our pension plan assets, the discount rate used to determine the service and interest cost components of our net periodic pension cost and assumed rates of increase in our employees’ future compensation. If our pension plan assets do not achieve positive rates of return, or if our estimates and assumed rates are not accurate, our company’s earnings may decrease because net periodic pension costs would rise and we could be required to provide additional funds to cover our obligations to employees under the pension plan.

ELECTRIC

We may experience fluctuations in revenues and expenses related to our electric operations, which may cause our financial results to fluctuate and could impair our ability to make distributions to shareholders or scheduled payments on our debt obligations.

A number of factors, many of which are beyond our control, may contribute to fluctuations in our revenues and expenses from electric operations, causing our net income to fluctuate from period to period. These risks include fluctuations in the volume and price of sales of electricity to customers or other utilities, which may be affected by factors such as mergers and acquisitions of other utilities, geographic location of other utilities, transmission costs (including increased costs related to operations of regional transmission organizations), changes in the manner in which wholesale power is sold and purchased, unplanned interruptions at our generating plants, the effects of regulation and legislation, demographic changes in our customer base and changes in our customer demand or load growth. Electric wholesale margins could be reduced as the MISO market becomes more efficient. Electric wholesale trading margins could be reduced or eliminated by losses due to trading activities. Other risks include weather conditions (including severe weather that could result in damage to our assets), fuel and purchased power costs and the rate of economic growth or decline in our service areas. A decrease in revenues or an increase in expenses related to our electric operations may reduce the amount of funds available for our existing and future businesses, which could result in increased financing requirements, impair our ability to make expected distributions to shareholders or impair our ability to make scheduled payments on our debt obligations. As of December 31, 2005 we had capitalized $1.8 million in costs related to the planned construction of a second electric generating unit at our Big Stone Plant site. If approvals of permits are not received on a timely basis, the project could be at risk. If the project is abandoned, any costs capitalized prior to abandonment would be subject to expense.

Actions by the regulators of our electric operations could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures.

The corporation is subject to government regulations and regulatory actions that may have a negative impact on its business and results of operations. The electric rates that we are allowed to charge for our electric services are one of the most important items influencing our financial position, results of operations and liquidity. The rates

that we charge our electric customers are subject to review and determination by state public utility commissions in Minnesota, North Dakota and South Dakota. We are also regulated by the Federal Energy Regulatory Commission. An adverse decision by one or more regulatory commissions concerning the level or method of determining electric utility rates, the authorized returns on equity, implementation of enforceable federal reliability standards or other regulatory matters, permitted business activities (such as ownership or operation of nonelectric businesses) or any prolonged delay in rendering a decision in a rate or other proceeding (including with respect to the recovery of capital expenditures in rates) could result in lower revenues and net income.

We may not be able to respond effectively to deregulation initiatives in the electric industry, which could result in reduced revenues and earnings.

We may not be able to respond in a timely or effective manner to the changes in the electric industry that may occur as a result of regulatory initiatives to increase wholesale competition. These regulatory initiatives may include further deregulation of the electric utility industry in wholesale markets. Although we do not expect retail competition to come to the states of Minnesota, North Dakota and South Dakota in the foreseeable future, we expect competitive forces in the electric supply segment of the electric business to continue to increase, which could reduce our revenues and earnings.

Our electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

Operation of electric generating facilities involves risks which can adversely affect energy output and efficiency levels. Most of our generating capacity is coal-fired. We rely on a limited number of suppliers of coal, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railroad for shipments of coal to our Big Stone and Hoot Lake Plants, making us vulnerable to increased prices for coal transportation from a sole supplier. Higher fuel prices result in higher electric rates for our retail customers through fuel clause adjustments and could make us less competitive in wholesale electric markets. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, intentional acts of destruction or other similar occurrences affecting the electric generating facilities. The loss of a major generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.

PLASTICS

Our plastics operations are highly dependent on a limited number of vendors for PVC resin and a limited supply of PVC resin. The loss of a key vendor, or any interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for our plastics business.

We rely on a limited number of vendors to supply the PVC resin used in our plastics business. Two vendors accounted for approximately 97% of our total purchases of PVC resin in 2005 and approximately 98% of our total purchases of PVC resin in 2004. In addition, the supply of PVC resin may be limited primarily due to manufacturing capacity and the limited availability of raw material components. The loss of a key vendor or any interruption or delay in the availability or supply of PVC resin could disrupt our ability to deliver our plastic products, cause customers to cancel orders or require us to incur additional expenses to obtain PVC resin from alternative sources, if such sources are available.

We compete against a large number of other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish our products from those of our competitors.

The plastic pipe industry is highly fragmented and competitive, due to the large number of producers and the fungible nature of the product. We compete not only against other PVC pipe manufacturers, but also against ductile iron steel, concrete and clay pipe manufacturers. Due to shipping costs, competition is usually regional, instead of national, in scope, and the principal areas of competition are a combination of price, service, warranty and product performance. Our inability to compete effectively in each of these areas and to distinguish our plastic pipe products from competing products may adversely affect the financial performance of our plastics business.

MANUFACTURING

Competition from foreign and domestic manufacturers, the price and availability of raw materials, the availability of production tax credits and general economic conditions could affect the revenues and earnings of our manufacturing businesses.

Our manufacturing businesses are subject to risks associated with competition from foreign and domestic manufacturers that have excess capacity, labor advantages and other capabilities that may place downward pressure on margins and profitability. Raw material costs for items such as steel, lumber, concrete, aluminum and resin have recently increased significantly and may continue to increase. Our manufacturers may not be able to pass on the cost of such increases to their respective customers. Each of our manufacturing companies has significant customers and concentrated sales to such customers. If our relationships with significant customers should change materially, it would be difficult to immediately and profitably replace lost sales. We believe the demand for wind towers that we manufacture will depend primarily on the existence of either renewable portfolio standards or a federal production tax credit for wind energy.

HEALTH SERVICES

Changes in the rates or methods of third-party reimbursements for our diagnostic imaging services could result in reduced demand for those services or create downward pricing pressure, which would decrease our revenues and earnings.

Our health services businesses derive significant revenue from direct billings to customers and third-party payors such as Medicare, Medicaid, managed care and private health insurance companies for our diagnostic imaging services. Moreover, customers who use our diagnostic imaging services generally rely on reimbursement from third-party payors. Adverse changes in the rates or methods of third-party reimbursements could reduce the number of procedures for which we or our customers can obtain reimbursement or the amounts reimbursed to us or our customers.

Our health services operations has a dealership and other agreements with Philips Medical from which it derives significant revenues from the sale and service of Philips Medical diagnostic imaging equipment.

This agreement can be terminated on 180 days written notice by either party for any reason. It also includes other compliance requirements. If this agreement were terminated within the notice provisions or we were not able to renew such agreements or comply with the agreement, the financial results of our health services operations would be adversely affected.

EX-21.A

Exhibit 21-A

OTTER TAIL CORPORATION

Subsidiaries of the Registrant
March 1, 2006

Company	State of Organization
Otter Tail Energy Services Company, Inc.		Minnesota
Overland Mechanical Services, Inc.		Minnesota
Otter Tail Assurance Limited		Cayman Islands
Varistar Corporation		Minnesota
Northern Pipe Products, Inc.		North Dakota
Vinyltech Corporation		Arizona
T.O. Plastics, Inc.		Minnesota
St. George Steel Fabrication, Inc.		Utah
DMI Industries, Inc.		North Dakota
DMI Canada, Inc.		Ontario, Canada
BTD Manufacturing, Inc.		Minnesota
ShoreMaster, Inc.		Minnesota
Galva Foam Marine Industries, Inc.		Missouri
Shoreline Industries, Inc.		Minnesota
DMS Health Technologies, Inc.		North Dakota
DMS Imaging, Inc.		North Dakota
DMS Imaging Partners, LLC		Delaware
DMS Leasing Corporation*		North Dakota
Midwest Construction Services, Inc.		Minnesota
Aerial Contractors, Inc.		North Dakota
Moorhead Electric, Inc.		Minnesota
Lynk3 Technologies, Inc		Minnesota
AC Equipment, Inc.		Minnesota
Ventus Energy Systems, Inc.		Minnesota
Foley Company		Missouri
Chassis Liner Corporation		Minnesota
E. W. Wylie Corporation		North Dakota
Idaho Pacific Holdings, Inc.		Delaware
Idaho-Pacific Corporation		Idaho
Idaho-Pacific Colorado Corporation		Delaware
AWI Acquisition Company Limited		Prince Edward Island, Canada
AgraWest Investments Limited		Prince Edward Island, Canada

* Inactive

EX-23

EXHIBIT 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-116206, 333-90952 and 333-11145 on Form S-3 and 333-25261, 333-73041 and 333-73075 on Form S-8 of our report dated February 20, 2006 (which expresses an unqualified opinion) relating to the consolidated financial statements of Otter Tail Corporation and its subsidiaries (the Company) and management’s report on the effectiveness of internal control over financial reporting (which includes an explanatory paragraph that an acquisition completed in August 2004 was included in the assessment of internal control over financial reporting for 2005 and indicates a change in internal controls for 2005 related to processes surrounding changes made within the MISO market) appearing in the 2005 Annual Report to Shareholders of the Company and incorporated by reference in this Annual Report on Form 10-K of the Company for the year ended December 31, 2005.

/s/ Deloitte & Touche LLP

Minneapolis, Minnesota

March 14, 2006

EX-24.A

Exhibit 24-A

POWER OF ATTORNEY

     I, KEVIN G. MOUG, do hereby constitute and appoint JOHN D. ERICKSON and GEORGE A. KOECK, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Chief Financial Officer and Treasurer of Otter Tail Corporation, the Annual Report of Otter Tail Corporation on Form 10-K for its fiscal year ended December 31, 2005, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended.

Date: February 6, 2006

          /s/ Kevin Moug

Kevin G. Moug

In Presence of:

/s/ Nathan Partain

/s/ Lauris Molbert

POWER OF ATTORNEY

     I, John MacFarlane, do hereby constitute and appoint JOHN D. ERICKSON and GEORGE A. KOECK, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Corporation, the Annual Report of Otter Tail Corporation on Form 10-K for its fiscal year ended December 31, 2005, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended.

Date: February 6, 2006

          /s/ John MacFarlane John MacFarlane

In Presence of:

/s/ John Erickson

/s/ Lauris Molbert

POWER OF ATTORNEY

     I, Karen Bohn, do hereby constitute and appoint JOHN D. ERICKSON and GEORGE A. KOECK, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Corporation, the Annual Report of Otter Tail Corporation on Form 10-K for its fiscal year ended December 31, 2005, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended.

Date: February 6, 2006

          /s/ Karen M. Bohn

Karen Bohn

In Presence of:

/s/ Thomas Brown

/s/ Gary Spies

POWER OF ATTORNEY

     I, Thomas Brown, do hereby constitute and appoint JOHN D. ERICKSON and GEORGE A. KOECK, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Corporation, the Annual Report of Otter Tail Corporation on Form 10-K for its fiscal year ended December 31, 2005, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended.

Date: February 6, 2006

          /s/ Thomas Brown

Thomas Brown

In Presence of:

/s/ Karen M. Bohn

/s/ Gary Spies

POWER OF ATTORNEY

     I, Dennis Emmen, do hereby constitute and appoint JOHN D. ERICKSON and GEORGE A. KOECK, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Corporation, the Annual Report of Otter Tail Corporation on Form 10-K for its fiscal year ended December 31, 2005, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended.

Date: February 6, 2006

          /s/ Dennis Emmen

Dennis Emmen

In Presence of:

/s/ Edward James McIntyre

/s/ Kenneth L. Nelson

POWER OF ATTORNEY

     I, Arvid Liebe, do hereby constitute and appoint JOHN D. ERICKSON and GEORGE A. KOECK, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Corporation, the Annual Report of Otter Tail Corporation on Form 10-K for its fiscal year ended December 31, 2005, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended.

Date: February 6, 2006

          /s/ Arvid Liebe

Arvid Liebe

In Presence of:

/s/ Kenneth L. Nelson

/s/ Robert N. Spolum

POWER OF ATTORNEY

     I, Kenneth Nelson, do hereby constitute and appoint JOHN D. ERICKSON and GEORGE A. KOECK, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Corporation, the Annual Report of Otter Tail Corporation on Form 10-K for its fiscal year ended December 31, 2005, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended.

Date: February 6, 2006

          /s/ Kenneth L. Nelson

Kenneth Nelson

In Presence of:

/s/ Dennis Emmen

/s/ Arvid R. Lieve

POWER OF ATTORNEY

     I, Nathan Partain, do hereby constitute and appoint JOHN D. ERICKSON and GEORGE A. KOECK, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Corporation, the Annual Report of Otter Tail Corporation on Form 10-K for its fiscal year ended December 31, 2005, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended.

Date: February 6, 2006

           /s/ Nathan Partain

Nathan Partain

In Presence of:

/s/ Joyce Nelson Schuette

/s/ Kevin Moug

POWER OF ATTORNEY

     I, Gary Spies, do hereby constitute and appoint JOHN D. ERICKSON and GEORGE A. KOECK, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Corporation, the Annual Report of Otter Tail Corporation on Form 10-K for its fiscal year ended December 31, 2005, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended.

Date: February 6, 2006

          /s/ Gary Spies

Gary Spies

In Presence of:

/s/ Thomas Brown

/s/ Karen M. Bohn

POWER OF ATTORNEY

     I, Robert Spolum, do hereby constitute and appoint JOHN D. ERICKSON and GEORGE A. KOECK, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Corporation, the Annual Report of Otter Tail Corporation on Form 10-K for its fiscal year ended December 31, 2005, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended.

Date: February 6, 2006

          /s/ Robert N. Spolum

Robert Spolum

In Presence of:

/s/ George Koeck

/s/ Kenneth L. Nelson

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John D. Erickson, certify that:

     1. I have reviewed this Annual Report on Form 10-K of Otter Tail Corporation;

     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

     (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

     (b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

     (c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

     (d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

     (a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

     (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 14, 2006

/s/ John D. Erickson John D. Erickson

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kevin G. Moug, certify that:

     1. I have reviewed this Annual Report on Form 10-K of Otter Tail Corporation;

     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

     (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

     (b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

     (c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

     (d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

     (a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

     (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 14, 2006

/s/ Kevin G. Moug Kevin G. Moug

Chief Financial Officer and Treasurer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Otter Tail Corporation (the “Company”) on Form 10-K for the period ended December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John D. Erickson, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ John D. Erickson

John D. Erickson

President and Chief Executive Officer

March 14, 2006

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Otter Tail Corporation (the “Company”) on Form 10-K for the period ended December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kevin G. Moug, Chief Financial Officer and Treasurer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Kevin G. Moug

Kevin G. Moug

Chief Financial Officer and Treasurer

March 14, 2006

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