##### Table of Contents



SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-K (Mark One)

    
    þ

    Annual Report pursuant to
Section 13 or 15(d) of theSecurities
Exchange Act of 1934For the fiscal year ended December 31, 2004ORo
    Transition Report pursuant to
Section 13 or 15(d) of theSecurities
Exchange Act of 1934For the transition period from to
 Commission File Number 0-368 OTTER TAIL CORPORATION  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: Title of each class
    
    Name of each exchange on which registeredNONE
    
    NONE
 Securities registered pursuant to Section 12(g) of the Act: COMMON SHARES, par value $5.00 per share
PREFERRED SHARE PURCHASE RIGHTS
CUMULATIVE PREFERRED SHARES, without par value
(Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. (Yes
 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.
o Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2
of the Act). (Yes þ  
No o ) The aggregate market value of the voting stock held by nonaffiliates, computed by reference to the
last sales price, on June 30, 2004 was $676,328,139. Indicate the number of shares outstanding of each of the registrants classes of Common Stock, as
of the latest practicable date: 29,136,737 Common Shares ($5 par value) as of February 28, 2005.
 Documents Incorporated by Reference: 2004 Annual Report to Shareholders-Portions incorporated by reference into Parts I and II
Proxy Statement dated March 7, 2005-Portions incorporated by
reference into Part III




---



TABLE OF CONTENTS  PART IItem 1. BUSINESSItem 2. ROPERTIESItem 3. LEGAL PROCEEDINGSItem 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSItem 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 2005)PART IIItem 5. MARKET FOR THE REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIESItem 6. SELECTED FINANCIAL DATAItem 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSItem 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKItem 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAItem 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREItem 9A. CONTROLS AND PROCEDURESItem 9B. OTHER INFORMATIONPART IIIItem 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTItem 11. EXECUTIVE COMPENSATIONItem 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERSItem 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONSItem 14. PRINCIPAL ACCOUNTANT FEES AND SERVICESPART IVItem 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULESSIGNATURESExhibit Index to Annual Report on Form 10-K For Year Ended December 31, 2004Portions of 2004 Annual Report to ShareholdersSubsidiariesConsent of Deloitte & Touche LLPPowers of AttorneyCertification of CEO Pursuant to Section 302Certification of CFO Pursuant to Section 302Certification of CEO Pursuant to Section 906Certification of CFO Pursuant to Section 906    Table of Contents  
 PART I 
 Item 1. BUSINESS (a) General Development of Business Otter Tail Corporation (the Company) was incorporated in 1907 under the laws of the State of
Minnesota. The Companys executive offices are located at 215 South Cascade Street, Box 496, Fergus
Falls, Minnesota 56538-0496 and 4334 18th Avenue SW, Suite 200, P.O. Box 9156, Fargo,
North Dakota 58106-9156. Its telephone number is (866) 410-8780. The Company makes available free of charge at its internet website (www.ottertail.com) its
annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, 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 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 2004, approximately 30% of the Companys consolidated operating revenues from
continuing operations and approximately 79% of the Companys consolidated income from continuing
operations came from electric operations. The Companys strategy is focused on the growth of its operating companies. The Companys
vision is to create value and growth through the acquisition, long-term ownership and decentralized
operation of diverse businesses. This strategy includes growing the core electric utility business
which provides a strong base of revenues, earnings and cash flows. In addition, the Company expects
its nonelectric operating companies to provide growth both organically and through acquisition.
Organic, internal growth comes from new products and services, market expansion and increased
efficiencies. 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
    Assessment of an operating companys business and the potential of future earnings
growth. The Company is a long-term owner of its operating companies and does not acquire companies in
pursuit of short-term gains. However, the Company will divest operating companies if they do not
meet these criteria over the long term. Otter Tail Corporation and its subsidiaries conducted business in all 50 states and in
international markets. The Company had approximately 3,380 full-time employees at December 31,
2004. The businesses of the Company have been classified into five segments: Electric, Plastics,
Manufacturing, Health Services and Other Business Operations. 1




---



##### Table of Contents




    Electric (the Utility) includes the production, transmission, distribution
and sale of electric energy in Minnesota, North Dakota and South Dakota under the name
Otter Tail Power Company. Electric utility operations have been the Companys primary
business since incorporation.
    Plastics 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, frame-straightening
equipment and accessories for the auto body shop industry, material and handling trays
and horticultural containers; fabrication of steel products; contract machining; and
metal parts stamping and fabrication. These businesses are located primarily in the
Upper Midwest, Missouri and Utah.
    Health Services consists of businesses involved in the sale of diagnostic
medical equipment, patient monitoring equipment and related supplies and accessories.
These businesses also provide service maintenance, 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.
    Other Business Operations consists of businesses involved in food ingredient
processing; 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 and
the food ingredient processing business that has sales in the United States, Canada,
Europe, the Middle East, the Pacific Rim and Central America. 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 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. 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 approximately $69.0 million in cash. An additional $6.0 million in cash was placed in
escrow to pay off earn-out contingencies if IPH achieves certain financial targets for the period
from August 1, 2004 through July 31, 2005. This acquisition adds a new platform to the Companys
diversified portfolio of businesses. IPH is 2




---



##### Table of Contents



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. For 2004 IPH was included in the Other Business Operations segment. As part of an ongoing evaluation of the prospects and growth opportunities of the Companys
business operations, the Company has decided to exit its telecommunications business Midwest
Information Systems, Inc. (MIS). On February 24, 2005, the Company entered into a Stock Purchase
Agreement with Arvig Enterprises, Inc. for the sale of MIS. The sale is contingent on approval of
the Minnesota Public Utilities Commission and other standard conditions of closing. As required in accordance with Statement of Financial Accounting Standard No. 144, Accounting
for the Impairment of Disposal of Long-Lived Assets, MIS has been accounted for as discontinued
operations in the Companys consolidated financial statements which are incorporated by reference
and filed as an Exhibit hereto. Prior to 2004, this business was included in the Other Business
Operations segment. MIS is headquartered in Parkers Prairie, MN and provides telephone, cable and internet
services with over 10,000 access lines for phone, internet and cable television to homes in rural
western Minnesota communities through its subsidiaries: Midwest Telephone Company, Osakis
Telephone Company, Peoples Telephone Company of Big Fork and Data Video Systems, Inc. As of
December 31, 2004 MIS had 20 full-time employees. For financial information regarding this business
see note 15 of Notes to Consolidated Financial Statements on pages 52 and 53 of the Companys
2004 Annual Report to Shareholders, filed as an Exhibit hereto. On February 2, 2005, the Company entered into a nonbinding letter of intent to sell the stock
of St. George Steel Fabrication, Inc. Located in Utah, St. George Steel fabricates structural steel
for buildings and bridges, as well as ductwork, conveyors, hoppers and plate steel products. 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 32 of the Companys 2004 Annual Report to Shareholders, filed as an Exhibit
hereto. (b) Financial Information About Industry Segments The Company is engaged in businesses that have been classified into five segments: Electric,
Plastics, Manufacturing, Health Services and Other Business Operations. Financial information about
the Companys segments and geographic areas is incorporated by reference to note 2 of Notes to
Consolidated Financial Statements on pages 43 through 45 of the Companys 2004 Annual Report to
Shareholders, filed as an Exhibit hereto. (c) Narrative Description of Business ELECTRIC General The Utility, which conducts business under the name of Otter Tail Power Company, provides
electricity to more than 128,000 customers in a 50,000 square mile area of Minnesota, North Dakota
and South Dakota. The Company derived 30% of its consolidated operating revenues from continuing
operations from the Electric segment in 2004, 36% in 2003 and 38% in 2002. The Company 3




---



##### Table of Contents



derived 79% of its consolidated income from continuing operations from the Electric segment in
2004, 91% in 2003 and 72% in 2002. The breakdown of retail revenues by state is as follows: State
    
    2004
    
    
    2003Minnesota
    
    
    50.3
    %
    
    
    50.2
    %North Dakota
    
    
    41.2
    
    
    
    41.4South Dakota
    
    
    8.5
    
    
    
    8.4Total
    
    
    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 and sales to municipalities and
farms. Customer category
    
    2004
    
    
    2003Commercial
    
    
    20.2
    %
    
    
    24.6
    %Residential
    
    
    23.5
    
    
    
    21.2Industrial
    
    
    14.3
    
    
    
    13.8All other sources
    
    
    42.0
    
    
    
    40.4Total
    
    
    100.0
    %
    
    
    100.0
    %
 Wholesale electric energy sales were 50.5% of total kwh sales for both 2004 and 2003.
Wholesale electric energy kwh sales grew 1.6% between the years and revenue per kwh increased by
9.4%. 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. However, the Company expects that market conditions for wholesale power transactions
in 2005 will not be as robust as in 2004 as a result in part to uncertainty in the wholesale
electric markets due to the expected implementation of Midwest Independent Transmission System
Operator electric markets on April 1, 2005. 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, 2004 the Utility served 128,218 customers. This is an increase of 684 customers from
December 31, 2003. Capability and Demand At December 31, 2004 and 2003 the Utility had base load net plant capability as follows: Base load net plant capability
    
    2004
    
    
    2003Big Stone Plant
    
    252,430
    kw
    
    252,360
    kwHoot Lake Plant
    
    
    152,450
    
    
    
    153,275Coyote Station
    
    
    149,450
    
    
    
    149,450Co-generation plant  Bemidji, MN (contract)
    
    
    5,661
    
    
    
    5,875Co-generation plant  Perham, MN (contract)
    
    
    1,228
    
    
    
    2,378Total
    
    561,219
    kw
    
    563,338
    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. 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 143,582 kw, and hydroelectric capability of 4,327 kw. During 2004, the Utility
generated about 77% of its retail kwh sales and purchased the balance. 4




---



##### Table of Contents



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 which extends through April 30, 2005 and another agreement to
purchase 50,000 kw of year-round capacity through April 30, 2010 from another utility. The Utility
has agreements to purchase the output from approximately 23,000 kw (nameplate rating) of wind
generating facilities. The December 2004 capacity rating of the wind generating facilities was
7,318 kw. 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, 2004 the Utility experienced an all-time system peak demand of 686,044 kw
on January 5, 2004. The highest sixty-minute peak demand prior to 2004 was 668,703 kw on February
10, 2003. Taking into account additional capacity available to it in January 2004 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 887,280 kw (774,640 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 2005 system demand, including industry reserve requirements. The Utility and a coalition of seven other electric providers are funding a study to explore
the feasibility of a second electric generating unit, tentatively named Big Stone II, at the site
of the existing Big Stone Plant near Milbank, South Dakota. The project would serve the investing
providers native customer loads and would be nominally rated 600 megawatts, rate-based and coal
fired or coal-and-biomass fired. The proposed plant would employ state-of-the-art coal burning and
environmental control technologies. If the investing providers decide to proceed, they are expected
to sign ownership and operating agreements in 2005. Permitting, which would require two years, and
construction, which would require four years, could lead to the plant being operational in 2011.
The Utility expects to be the operating partner and its ownership investment in the project is
expected to be approximately 18%. 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 2004 and 2003: 2004
    
    
    2003Net Kilowatt
    
    
    % of Total
    
    
    Net Kilowatt
    
    
    % of TotalHours
    
    
    Kilowatt
    
    
    Hours
    
    
    KilowattGenerated
    
    
    Hours
    
    
    Generated
    
    
    HoursSources
    
    (Thousands)
    
    
    Generated
    
    
    (Thousands)
    
    
    GeneratedSubbituminous Coal
    
    
    2,605,014
    
    
    
    69.0
    %
    
    
    2,668,421
    
    
    
    72.7
    %Lignite Coal
    
    
    1,114,485
    
    
    
    29.5
    
    
    
    955,304
    
    
    
    26.0Hydro
    
    
    20,689
    
    
    
    .6
    
    
    
    14,778
    
    
    
    .4Natural Gas and Oil
    
    
    33,927
    
    
    
    .9
    
    
    
    34,114
    
    
    
    .9Total
    
    
    3,774,115
    
    
    
    100.0
    %
    
    
    3,672,617
    
    
    
    100.0
    %
 The Utility has primary coal supply agreements with Arch Coal Sales and Kennecott Coal Sales
Company for the supply of Wyoming subbituminous coal to 5




---



##### Table of Contents



Big Stone Plant for 2005 through 2007. Purchases are made for the supply of subbituminous coal
for the Hoot Lake Plant under a contract with Kennecott Coal Sales Company through December 31,
2007. A lignite coal contract with Dakota Westmoreland Corporation for the Coyote Station expires
in 2016, with a 15-year renewal option subject to certain contingencies. It is the Utilitys practice to maintain minimum 30-day inventory (at full output) of coal at
the Big Stone Plant, a 20-day inventory at the Coyote Station and a 15-day inventory at the Hoot
Lake Plant. Railroad transportation services to the Big Stone Plant are being provided under a common
carrier rate by the Burlington Northern and Santa Fe Railroad Co. The Company has filed a complaint
in regard to this rate with the Surface Transportation Board requesting the Board set a competitive
rate. The Surface Transportation Board issued orders in December 2004 and January 2005 that called
for the final evidentiary submissions and adopted a procedural schedule that would require a final
decision by January 21, 2006. The Company would expect the outcome of the proceeding to have a
favorable impact on its fuel costs for Big Stone Plant. Railroad transportation services to the
Hoot Lake Plant are being provided under a common carrier rate by the Burlington Northern and Santa
Fe Railroad Co. On July 1, 2004, the existing rail carrier 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 2004 the fuel surcharge, which is in addition to
the freight rate, ranged from 6.5% to 11.5% as a percent of the tariff rate. 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 2004, 2003 and 2002 was $1.229, $1.189 and $1.125, respectively. The Utility is permitted by the State of South Dakota to burn some alternative fuels,
including tire-derived fuel and biomass, at the Big Stone Plant. The quantity of alternative fuel
burned at the Big Stone Plant is insignificant when compared to the total annual coal consumption
at the Big Stone Plant. General Regulation The Utility is subject to regulation of rates and other matters in each of the three states in
which it operates and by the federal government for certain interstate operations. A breakdown of
electric rate regulation by each jurisdiction is as follows: 2004
    
    
    2003% of
    
    
    
    
    
    
    % ofElectric
    
    


%
of kwh
    
    
    Electric

    
    


%
of kwhRates
    
    Regulation
    
    Revenues
    
    
    Sales
    
    
    Revenues
    
    
    SalesMN retail sales
    
    MN Public Utilities Commission
    
    
    29.3
    %
    
    
    25.7
    %
    
    
    30.2
    %
    
    
    25.3
    %ND retail sales
    
    ND Public Service Commission
    
    
    24.1
    
    
    
    19.6
    
    
    
    25.0
    
    
    
    20.0SD retail sales
    
    SD Public Utilities Commission
    
    
    4.9
    
    
    
    4.2
    
    
    
    5.0
    
    
    
    4.2Transmission &
sales for resale
    
    Federal Energy Regulatory Commission
    
    
    41.7
    
    
    
    50.5
    
    
    
    39.8
    
    
    
    50.5100.0
    %
    
    
    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. 6




---



##### Table of Contents



The pattern of electric usage can vary dramatically during a 24-hour period and from season to
season. The Utilitys tariffs provide for continuous electric service and are designed to cover the
costs of service during peak times. To the extent that peak usage can be reduced or shifted to
periods of lower usage, the cost to serve all customers is reduced. In order to shift usage from
peak times, the Utility has approved tariffs in all three states for lower rates for residential
demand control and controlled service, in Minnesota and North Dakota for real-time pricing, and in
North Dakota and South Dakota for bulk interruptible rates. Each of these specialized rates is
designed to improve efficient use of the Utility facilities, while encouraging use of
cost-effective electricity instead of other fuels and giving customers more control over the size
of their electric bill. In all three states, the Utility has approved tariffs which allow
qualifying customers to release and sell energy back to the Utility when wholesale energy prices
make such transactions desirable. The majority of the Utilitys electric retail rate schedules now in effect provide for
adjustments in rates based on the cost of fuel delivered to the Utilitys generating plants, as
well as for adjustments based on the cost of electric energy purchased by the Utility. Such
adjustments are presently based on a two-month moving average in Minnesota and under FERC, a
three-month moving average in South Dakota and a four-month moving average in North Dakota. These
adjustments are applied to the next billing period after becoming applicable. The following summarizes the material regulations of each jurisdiction applicable to the
Utilitys electric operations, as well as the specific electric rate proceedings during the last
three years with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service
Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the Federal Energy
Regulatory Commission (FERC). The Companys nonelectric businesses are not subject to direct
regulation by any of these agencies. Minnesota: Under the Minnesota Public Utilities Act, the Utility is subject to the
jurisdiction of the MPUC with respect to rates, issuance of securities, depreciation rates, public
utility services, construction of major utility facilities, establishment of exclusive assigned
service areas, contracts and arrangements with subsidiaries and other affiliated interests, and
other matters. The MPUC has the authority to assess the need for large energy facilities and to
issue or deny certificates of need, after public hearings, within six months of an application to
construct such a facility. The Utility has not had a significant rate proceeding before the MPUC
since July 1987. 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 7




---



##### Table of Contents



improvement may belong to the property owner rather than the utility. Since 1995, the Utility
has recovered demand-side management related costs not included in base rates under Minnesotas
Conservation Improvement Programs through the use of an annual recovery mechanism approved by the
MPUC. The MPUC requires the submission of a 15-year advance integrated resource plan by utilities
serving at least 10,000 customers, either directly or indirectly, and having at least 100 megawatts
of load. The MPUCs findings and orders with respect to these submissions are binding for
jurisdictional utilities. Typically, the filings are submitted every two years. The Utilitys most
recent plan was submitted to the MPUC in 2002 and was approved early in 2003. The MPUC also granted
the Utility a one-year waiver in submitting its next integrated resource plan, which will be
completed in 2005. The MPUC requires the annual filing of a capital structure petition. In this filing the MPUC
reviews and approves the capital structure for the Company. Once the petition is approved, the
Company may issue securities without further petition or approval, provided the issuance is
consistent with the purposes and amounts set forth in the approved capital structure petition. The
Companys current capital structure petition is in effect until April 14, 2005. The Company filed
its capital structure petition for 2005 on March 4, 2005 and expects to receive approval from the
MPUC prior to April 14, 2005. The Minnesota legislature has enacted a statute that favors conservation over the addition of
new resources. In addition, it has mandated the use of renewable resources where new supplies are
needed, unless the utility proves that a renewable energy facility is not in the public interest.
It has effectively prohibited the building of new nuclear facilities. An existing environmental
externality law requires the MPUC, to the extent practicable, to quantify the environmental costs
of each type of generation, and to use such monetized values in evaluating resource plans. The MPUC
must disallow any nonrenewable rate base additions (whether within or outside of the state) or any
rate recovery therefrom, and may not approve any nonrenewable energy facility in an integrated
resource plan, unless the utility proves that a renewable energy facility is not in the public
interest. The state has prioritized the acceptability of new generation with wind and solar ranked
first and coal and nuclear ranked fifth, the lowest ranking. Pursuant to the Minnesota Power Plant Siting Act, the Minnesota Environmental Quality Board
(EQB) has been granted the authority to regulate the siting in Minnesota of large electric power
generating facilities in an orderly manner compatible with environmental preservation and the
efficient use of resources. To that end, the EQB is empowered, after study, evaluation and
hearings, to select or designate sites in Minnesota for new electric power generating plants
(50,000 kw or more) and routes for transmission lines (100 kv or more) and to certify such sites
and routes as to environmental compatibility. The Minnesota Legislature enacted the Minnesota Energy Security and Reliability Act in 2001.
Its primary focus was to streamline the siting and routing processes for the construction of new
electric generation and transmission projects. The bill also added to utility requirements for
renewable energy and energy conservation. North Dakota: The Utility is subject to the jurisdiction of the NDPSC with respect to
rates, services, certain issuances of securities and other matters. The NDPSC periodically performs
audits of gas and electric utilities over which it has rate setting jurisdiction to determine the
reasonableness of overall rate levels. In the past, these audits have occasionally resulted in
settlement agreements adjusting rate levels for the Utility. The North Dakota Energy Conversion and
Transmission Facility Siting Act grants the NDPSC the authority to approve sites in North Dakota
for large electric generating facilities and high voltage transmission lines. This Act is similar
to the Minnesota Power Plant Siting Act described above and applies to proposed new electric power
generating plants of 50,000 kw or more and proposed new 8




---



##### Table of Contents



transmission lines of more than 115 kv. The Utility is required to submit a ten-year plan to the
NDPSC annually. On December 29, 2000 the NDPSC approved a performance-based ratemaking (PBR) plan that links
allowed earnings in North Dakota to seven performance standards in the areas of price, electric
service reliability, customer satisfaction and employee safety. The PBR plan is effective through
2005, unless suspended or terminated by the NDPSC or the Utility. This PBR plan provides the
opportunity for the Utility to raise its allowed rate of return and share income with customers
when earnings exceed the allowed return. During 2001, the Utility achieved a rate of return on
equity that exceeded targets under the plan, resulting in a sharing of the income between
shareholders and customers in the form of a $662,300 refund to North Dakota retail electric
customers in 2002. Because the Utilitys 2003 and 2002 rates of return were within the allowable
range defined in the plan, no sharing occurred. The Utilitys 2004 rate of return is expected to
be within the allowable range defined in the plan. The NDPSC reserves the right to review the issuance of stocks, bonds, notes and other
evidence of indebtedness of a public utility. However, the issuance by a public utility of
securities registered with the Securities and Exchange Commission is expressly exempted from
review by the NDPSC under North Dakota state law. South Dakota: The South Dakota Public Utilities Act subjects the Utility to the
jurisdiction of the SDPUC with respect to rates, public utility services, establishment of assigned
service areas and other matters. The Utility is not currently subject to the jurisdiction of the
SDPUC with respect to the issuance of securities. Under the South Dakota Energy Facility Permit
Act, the SDPUC has the authority to approve sites in South Dakota for large energy conversion
facilities (100,000 kw or more) and transmission lines of 115 kv or more. There have been no
significant rate proceedings in South Dakota since November 1987. FERC: Wholesale power sales and transmission rates are subject to the jurisdiction of
the FERC under the Federal Power Act of 1935, as amended (FPA). The FERC is an independent agency
which has jurisdiction over rates for electricity sales for resale, transmission and sale of
electric energy in interstate commerce, interconnection of facilities, and accounting policies and
practices. Filed rates are effective after a one-day suspension period, subject to ultimate
approval by the FERC. 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, Midwest ISO,
Southwest Power Pool, PJM Interconnection, LLP 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 ten 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, thus ensuring
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 9




---



##### Table of Contents



use load than MAPP. The MRO region includes more than forty members supplying approximately
280 million megawatt-hours to more than twenty million people. Its membership is comprised of
municipal utilities, cooperatives, investor-owned utilities, a federal power marketing agency,
Canadian Crown Corporations and independent power producers. MISO: The Utility agreed in October 2001 to join the Midwest Independent Transmission
System Operator, Inc. (MISO) pursuant to FERC Order No. 2000. In December 2001, the MISO received
FERC approval to operate as an independent regional transmission organization. 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
optimizes the efficiency of the interconnected system, provides regional solutions to regional
planning needs and continually minimizes any risk to reliability through its security coordination,
long-term regional planning, market monitoring, scheduling and tariff administration functions. Energy Markets: In July 2002, the FERC issued a Notice of Proposed Rulemaking (NOPR)
on Standard Market Design (SMD). Its purpose is to insure standard commercial rules for the
operation of competitive markets for electricity. The MISO Energy Markets are expected to commence
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 cost effects to the Utilitys retail customers and its wholesale
margins are unknown. Other: The Utility is subject to various federal and state laws, including the Federal
Public Utility Regulatory Policies Act and the Energy Policy Act of 1992, which are intended to
promote the conservation of energy and the development and use of alternative energy sources. The
Utility may also become subject to comprehensive energy legislation currently pending before the
United States Congress. The Utility is unable to predict the impact on its operations resulting from future regulatory
activities, from future legislation or from future tax that may be imposed on the source or use of
energy. Competition, Deregulation and Legislation Electric sales are subject to competition in some areas from municipally owned systems, rural
electric cooperatives and, in certain respects, from on-site generators and cogenerators.
Electricity also competes with other forms of energy. The degree of competition may vary from time
to time depending on relative costs and supplies of other forms of energy. The Utility may also
face competition as the restructuring of the electric industry evolves. The Company believes the Utility is well positioned to be successful in a more competitive
environment. A comparison of the Utilitys electric retail rates to the rates of other
investor-owned utilities, cooperatives and municipals in the states the Utility serves indicates
that the Utilitys rates are competitive. In addition, the Utility would attempt more flexible
pricing strategies under an open, competitive environment. 10




---



##### Table of Contents



Legislative and regulatory activity could affect operations in the future. The Utility cannot
predict the timing or substance of any future legislation or regulation. State and federal efforts
to restructure the electric utility industry have slowed. The United States Congress ended its 2004
legislative session without passing electric industry restructuring legislation or a comprehensive
energy bill. 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 2005
legislative sessions in those states. The Company does not expect retail competition to come to the
States of Minnesota, North Dakota or South Dakota in the foreseeable future. Environmental Regulation Impact of Environmental Laws: The Utilitys existing generating plants are subject to
stringent federal and state standards and regulations regarding, among other things, air, water and
solid waste pollution. The Utility estimates it has expended in the five years ended December 31,
2004 approximately $6.0 million for environmental control facilities. Included in the 2005-2009
construction budget are approximately $5.6 million for environmental equipment for existing and new
facilities, including $3.5 million for 2005. Air Quality: Pursuant to the Federal Clean Air Act of 1970 as amended (the Act), the
United States Environmental Protection Agency (EPA) has promulgated national primary and secondary
standards for certain air pollutants. The primary fuels burned by the Utilitys steam generating plants are North Dakota lignite
coal and western subbituminous coal. Electrostatic precipitators have been installed at the
principal units at the Hoot Lake Plant. A fabric filter to collect particulates from stack gases
has been installed on a smaller unit at Hoot Lake Plant. As a result, the units at the Hoot Lake
Plant currently meet all presently applicable federal and state air quality and emission standards. 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. As a result of the assessment finding, the
Big Stone Plant co-owners plan to replace the remaining four precipitator fields with Advanced
Hybrid technology. 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 11




---



##### Table of Contents



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 2004. The EPA Administrator signed the final Interstate Air Quality 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 Utilities service
territory are slated for NOx reduction for ambient air quality 8-hour ozone non-attainment
purposes. The Utility is currently evaluating the rule and is unable to assess its impact at this
time. 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 expects to issue final rules by March 15, 2005. Because
promulgation of rules by the EPA has not been completed, it is not possible to assess to what
extent this regulation will impact the Utility. 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. 12




---



##### Table of Contents



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 has been completed and the results have
been submitted to the EPA for their review. Pending the outcome of the EPA review, it appears that
a cap on the SO2 emissions may not be necessary to insure compliance with the PSD requirements. The Dakota Resource Council filed a civil action against the EPA asking that the Court order
EPA to perform the alleged non-discretionary duty of requiring the State of North Dakota to take
steps to remedy alleged unlawful levels of SO2 in Theodore Roosevelt National Park, Lostwood
Wilderness Area, Medicine Lakes Wilderness Area, and Fort Peck Indian Reservation. The Utility
joined with other North Dakota utilities in a Motion to Intervene in this proceeding. On April 2,
2004 the U.S. District Court for the District of Colorado dismissed the suit for lack of subject
matter jurisdiction. 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 been issued 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 in principle identifying the remediation
technology. The preliminary estimate of remediation costs to address the 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 13




---



##### Table of Contents



solid and hazardous waste statutes and regulations enacted by the federal government or the
States of Minnesota, North Dakota and South Dakota is not certain at this time. In 1980, the United States enacted the Comprehensive Environmental Response, Compensation and
Liability Act, commonly known as the Federal Superfund law, which was reauthorized and amended in
1986. In 1983, Minnesota adopted the Minnesota Environmental Response and Liability Act, commonly
known as the Minnesota Superfund law. In 1988, South Dakota enacted the Regulated Substance
Discharges Act, commonly known as the South Dakota Superfund law. In 1989, North Dakota enacted the
Environmental Emergency Cost Recovery Act. Among other requirements, the federal and state acts
establish environmental response funds to pay for remedial actions associated with the release or
threatened release of certain regulated substances into the environment. These federal and state
Superfund laws also establish liability for cleanup costs and damage to the environment resulting
from such release or threatened release of regulated substances. The Minnesota Superfund law also
creates liability for personal injury and economic loss under certain circumstances. The Utility is
unable to determine the total impact of the Superfund laws on its operations at this time but has
not incurred any significant costs to date related to these laws. The Utility is not presently
named as a potentially responsible party under the federal or state Superfund laws. Capital Expenditures The Utility is continually expanding, replacing and improving its electric facilities. During
2004, approximately $25.4 million was invested for additions and replacements to its electric
utility properties. During the five years ended December 31, 2004 gross electric property
additions, including construction work in progress, were approximately $166.4 million and gross
retirements were approximately $54.0 million. The Utility estimates that during the five-year period 2005-2009 it will invest approximately
$135 million for electric construction. The Utility continuously reviews options for increasing its
generating capacity. It is currently involved in a feasibility study with seven other electric
providers for a jointly owned 600-megawatt coal fired or coal-and-biomass fired generating unit at
the site of the existing Big Stone Plant. Capital expenditures related to this new facility are not
included in the projected capital expenditures for 2005-2009. At this time the Utility has no firm
plans for any other additional base load generating plant construction. The majority of electric
utility expenditures for the five-year period 2005 through 2009 will be for work related to the
Utilitys transmission and distribution systems. Franchises At December 31, 2004 the Utility had franchises to operate as an electric utility in all of
the 371 incorporated municipalities that it serves. All franchises are nonexclusive and generally
were obtained for 20-year terms, with varying expiration dates. No franchises are required to serve
unincorporated communities in any of the three states that the Utility serves. There are 38
franchises that are set to expire during 2005. The Utility believes that these franchises will be
renewed. Employees At December 31, 2004 the Utility had approximately 646 full-time employees. A total of 338
employees are represented by local unions of the International Brotherhood of Electrical Workers.
These labor contracts expire in the fall of 2005. The Utility has not experienced any strike, work
stoppage or strike vote, and considers its present relations with employees to be good. 14




---



##### Table of Contents



PLASTICS General Plastics consist of businesses producing polyvinyl chloride (PVC) and polyethylene (PE) pipe.
The Company derived 13% of its consolidated operating revenues from continuing operations from this
segment in 2004, 12% in 2003 and 13% in 2002. The following is a brief description of these businesses: Northern Pipe Products, Inc., located in Fargo, ND, manufactures and sells PVC and
PE pipe for municipal water, rural water, wastewater and other uses in the Northern,
Midwestern and Western regions of the United States as well as Canada. The production
facility for PVC pipe is located in Fargo, ND and the production facility for PE pipe is
located in Hampton, IA. Vinyltech Corporation, located in Phoenix, AZ, manufactures and sells PVC pipe for
municipal water, wastewater, water reclamation systems and other uses in the Western,
Southwest and South Central regions of the United States. Together these companies have the capacity to produce approximately
200 million pounds of PVC and PE pipe annually. Customers The PVC and PE pipe products are marketed through a combination of independent sales
representatives, company salespersons and customer service representatives. Customers for the PVC
and PE pipe products consist primarily of wholesalers and distributors throughout the Upper
Midwest, Southwest and Western United States. Competition The plastic pipe industry is highly 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 ten
years, there has been consolidation in PVC resin producers. There are a limited number of third
party vendors that supply the PVC resin used by Northern Pipe and Vinyltech. Two vendors provided 15




---



##### Table of Contents



approximately 98% and 96% of total resin purchases in 2004 and 2003, respectively. The supply of
PVC resin may also be limited 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 supply of PVC
resin, could disrupt the ability of the Plastics segment to manufacture products, cause customers
to cancel orders or require incurrence of additional expenses to obtain PVC resin from alternative
sources, if such sources were available. Both Northern Pipe and Vinyltech believe they have good
relationships with their key raw material vendors. Due to the commodity nature of PVC resin and PVC pipe and the dynamic supply and demand
factors worldwide, historically the markets for both PVC resin and PVC pipe have been very cyclical
with significant fluctuations in prices and gross margins. Capital Expenditures Capital expenditures in the Plastics segment typically include investments in extrusion
machines, land and buildings and management information systems. During 2004, capital expenditures
of approximately $2.5 million were made in the Plastics segment. Total capital expenditures during
the five-year period 2005-2009 are estimated to be approximately $10 million. Employees At December 31, 2004 the Plastics segment had approximately 169 full-time employees. MANUFACTURING General Manufacturing consists of businesses in the following manufacturing activities: production of
waterfront equipment, wind towers, frame-straightening equipment and accessories for the auto body
shop industry, material and handling trays and horticultural containers; fabrication of steel products; contract
machining; and metal parts stamping and fabrication. The Company derived 26% of its consolidated operating revenues from continuing operations from
this segment in 2004, 24% in 2003 and 22% in 2002. The following is a brief description of each of
these businesses: BTD Manufacturing, Inc. (BTD), located in Detroit Lakes and Pelican Rapids, MN, is a
metal stamping and tool and die manufacturer that provides its services mainly to customers
in the Midwest. BTD stamps, fabricates, welds and laser cuts metal components according to
manufacturers specifications primarily for the recreation vehicle, gas fireplace, health
and fitness and enclosure industries. On January 3, 2005 BTD acquired the assets of
Performance Tool & Die Inc., a manufacturer of mid to large-sized dies located in Lakeville, MN
for $4.0 million. Chassis Liner Corporation, located in Alexandria and Lucan, MN, manufactures and
markets vehicle frame-straightening equipment and accessories used by the auto repair
industry throughout the United States. DMI Industries, Inc., located in West Fargo, ND, engineers and manufactures wind
towers and other heavy metal fabricated products throughout the United States. ShoreMaster, Inc., located in Fergus Falls, MN, along with its wholly owned
subsidiary, Galva Foam Marine Industries, Inc. located in Camdenton, MO, produces
residential and commercial waterfront equipment, ranging from boatlifts and docks to full
marina systems that are 16




---



##### Table of Contents



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, MN for
$2.2 million. St. George Steel Fabrication, Inc., located in St. George and Salt Lake City, UT,
fabricates structural steel members for buildings and bridges, ductwork for the power and
refining industries, conveyors and hoppers for mining and industrial markets and plate steel
products for the wind tower industry, primarily for customers in the Western United States.
On February 2, 2005, the Company entered into a nonbinding letter of intent to sell St.
George Steel. T. O. Plastics, Inc., located in Minneapolis and Clearwater, MN, and Hampton, SC,
manufactures and sells plastic thermoformed products for the horticulture industry
throughout the United States. In addition, T. O. Plastics produces products such as clamshell packing, blister packs, returnable
pallets and handling trays for shipping and storing odd-shaped or difficult-to-handle parts
for other industries. Competition The various markets in which the Manufacturing segment entities compete are characterized by
intense competition 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 their high-performance products, innovative technologies,
cost-effective manufacturing techniques, close customer relations and support, and their strategy
of increasing product offerings. Some of the products sold by the companies in the Manufacturing segment are purchased by
companies in the recreational vehicle, wind energy and auto repair markets. A downturn in these
markets could have an adverse impact on the financial results of the Companys Manufacturing
segment. Steel Supply Many of companies in the Manufacturing segment use a variety of steel in the products that
they manufacture. Steel prices have increased significantly due to a number of factors including
demand from Chinas expanding economy, elevated energy prices that increase the cost of making
steel, a shortage of coke (a substance made from coal that is used in making steel) and the falling
dollar increasing the cost of imported steel. Both pricing and availability are concerns of steel
users. Some steel companies are adding surcharges to offset their higher costs. The companies in
the Manufacturing segment will attempt to pass the surcharges on to their customers. The increase
in steel prices could have a negative affect on profit margins in the Manufacturing segment. Legislation The demand for wind towers that are manufactured by DMI Industries will depend primarily on
the existence of a federal production tax credit for wind energy. In October 2004 federal
legislation extended the production tax credit through 2005. The failure of Congress to pass a
broad energy bill in 2005 and extend the production tax credit beyond 2005 could have an
unfavorable impact on DMI Industries. 17




---



##### Table of Contents



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 2004, capital expenditures of approximately
$13.5 million were made in the Manufacturing segment. Total capital expenditures for the
Manufacturing segment during the five-year period 2005-2009 are estimated to be approximately $47
million. Employees At December 31, 2004 the Manufacturing segment had approximately 1,285 full-time employees. HEALTH SERVICES General Health Services consists of the DMS Health Group, which includes businesses involved in the
sale of diagnostic medical equipment, patient monitoring equipment and related supplies and
accessories. These businesses also provide service maintenance, diagnostic imaging, positron
emission tomography and nuclear medicine imaging, portable X-ray imaging and rental of diagnostic
medical imaging equipment. The Company derived 13% of its consolidated operating revenues from continuing operations from
this segment in 2004, 13% in 2003 and 15% in 2002. The companies comprising the DMS Health Group
that deliver diagnostic imaging and healthcare solutions across the United States include: DMS Health Technologies, Inc. (DMS), located in Fargo, ND, sells, services and
refurbishes diagnostic medical imaging equipment, patient monitoring equipment and related
supplies and accessories. DMS sells radiology equipment primarily manufactured by Philips
Medical Systems (Philips), a large multi-national company based in the Netherlands. Philips
manufactures fluoroscopic, radiographic and mammography equipment, along with ultrasound,
computerized tomography (CT) scanners, magnetic resonance imaging (MRI) scanners and cardiac
cath labs. The dealership agreement with Philips can be terminated on 180 days written
notice by either party for any reason. The Philips agreement also can be terminated by
Philips if certain compliance requirements are not met. DMS is also a supplier of medical
film and related accessories. DMS markets mainly to hospitals, clinics and mobile imaging
service companies. DMS Imaging, Inc., a subsidiary of DMS Health Technologies, Inc. located in
Minneapolis, MN, operates diagnostic medical imaging equipment, including CT, MRI,
positron-emission tomography (PET), nuclear medicine services and other similar radiology
services to hospitals, clinics, long-term care facilities and other medical providers.
Regional offices are located in Houston, TX; Minneapolis, MN; and Sioux Falls, SD. DMS
Imaging provides services through four different business units:  
    DMS Imaging  provides shared diagnostic medical imaging services
(primarily mobile) for MRI, CT, nuclear medicine, PET, ultrasound,
mammography and bone density analysis.
    DMS Interim Solutions  offers interim and rental options for diagnostic
imaging services.
    DMS MedSource Partners  develops long-term relationships with
healthcare providers to offer dedicated in-house diagnostic imaging
services, such as MRI. 18




---



##### Table of Contents




    DMS Portable X-Ray  delivers portable X-ray, ultrasound and
electrocardiogram services to nursing homes and other facilities. Combined, the DMS Health Group covers the three basics of the medical imaging industry: (1)
ownership and operation of the imaging equipment for healthcare providers; (2) sale, lease and/or
maintenance of medical imaging equipment and related supplies; and (3) scheduling, billing and
administrative support of medical imaging services. Regulation The healthcare industry is subject to federal and state regulations relating to licensure,
conduct of operation, ownership of facilities, payment of services and 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 penalties 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 physician referrals of
Medicare patients to an entity providing certain designated health services, including services
provided by the Health Services companies. The Stark Law also prohibits an entity to bill 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. 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. 19




---



##### Table of Contents



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 who are healthcare providers 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.  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 MRI services, have access to
greater financial resources than the Health Services companies. In addition, some of Health
Services customers are capable of providing the same services to their patients directly, subject
only to their decision to acquire a high-cost diagnostic imaging system, assume the financial and
technology risk, and employ the necessary technologists, rather than obtain the services from the
Health Services company. The Health Services companies may also experience greater competition in
states that currently have certificate of need laws if such laws were repealed, thereby reducing
barriers to entry and competition in that state. The Health Services companies compete against
other similar providers on the basis of quality of services, quality and magnetic
field strength of imaging systems, relationships with health care providers,
knowledge and service quality of technologists, price, availability and reliability. Environmental, Health or Safety Laws Positron emission tomography services and some other imaging services require the use of
radioactive material. While this material has a short life 20




---



##### Table of Contents



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 2004, capital expenditures of approximately
$3.9 million were made in the Health Services segment. Total capital expenditures during the
five-year period 2005-2009 are estimated to be approximately $5 million. Operating leases are also
used to finance the acquisition of medical equipment used by Health Services companies. Current
operating lease commitments during the five-year period 2005-2009 are estimated to be $86 million. Employees At December 31, 2004 the Health Services segment had approximately 389 full-time employees. OTHER BUSINESS OPERATIONS General Other Business Operations consists of businesses involved in food ingredient processing;
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. On August 18, 2004 the Company acquired all of the outstanding common stock of Idaho Pacific
Holdings, Inc. (IPH) The Company derived 18% of its consolidated operating revenues from continuing operations from
these businesses in 2004 and 15% in 2003 and 12% in 2002. Following is a brief description of each
of these businesses. Foley Company, headquartered in Kansas City, MO, 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. Idaho Pacific Holdings, Inc., headquartered in Ririe, ID, manufacturers and supplies
dehydrated potato products to food manufacturers in the snack food, foodservice and bakery
industries. IPH has three processing facilities located in Ririe, ID, Center, CO and Souris,
Prince Edward Island, Canada. IPH sells to customers in the United States and Canada and
exports potato products to Europe, the Middle East, the Pacific Rim and Central America. Midwest Construction Services, Inc., located in Moorhead, MN, is a holding company
for five subsidiaries that provide 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. 21




---



##### Table of Contents



Otter Tail Energy Services Company, headquartered in Fergus Falls, MN, 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, ND, is a contract and common
carrier operating a fleet of tractors and trailers in 48 states and 6 Canadian provinces.
Wylie has trucking terminals in Fargo, ND, Des Moines, IA, Fort Worth, TX, and Chicago, IL. Competition Each of the businesses in Other Business Operations is subject to competition, as well as the
effects of general economic conditions in their respective industries. The construction companies
in this segment must compete with other construction companies in the Upper Midwest and the Central
regions of the United States when bidding on new projects. The Company believes the principal
competitive factors in the construction segment are price, quality of work and customer services. The market for processed, dehydrated potato flakes, flour and granules is highly competitive.
IPH competes with numerous manufacturers of varying sizes in the United States. Competition is
based on superior product quality, product pricing, strong customer relationships, raw material
costs and availability, and customer demand for finished goods. The trucking industry, in which Wylie competes, is highly competitive. Wylie competes
primarily with other short- to medium-haul, flatbed truckload carriers, internal shipping conducted
by existing and potential customers and, to a lesser extent, railroads. Competition for the freight
transported by Wylie is based primarily on service and efficiency and to a lesser degree, on
freight rates. There are other trucking companies that have greater financial resources, operate
more equipment or carry a larger volume of freight than Wylie and these companies compete with
Wylie for qualified drivers. Capital Expenditures Capital expenditures in this segment typically include investments in additional trucks and
flat bed trailers, construction equipment and processing equipment used in the dehydration process.
During 2004, capital expenditures of approximately $4.5 million were made in Other Business
Operations. Capital expenditures during the five-year period 2005-2009 are estimated to be
approximately $14 million for Other Business Operations. Employees At December 31, 2004 there were approximately 891 full-time employees in Other Business
Operations. 114 employees of Moorhead Electric, Inc. a subsidiary of Midwest Construction Services,
Inc., are represented by a local union of the International Brotherhood of Electrical Workers and
are covered by a labor contract that expires on May 31, 2005. Foley Company has 91 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 ranging from March 31, 2005 through December 31, 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. 22




---



##### Table of Contents



Forward Looking Information  Safe Harbor Statement Under the Private Securities Litigation
Reform Act of 1995 In connection with the safe harbor provisions of the Private Securities Litigation Reform
Act of 1995 (the Act), the Company has filed cautionary statements identifying important factors
that could cause the Companys actual results to differ
materially from those discussed in forward-looking statements made by or on behalf of the Company. When used in this Form 10-K and in
future filings by the Company with the Securities and Exchange Commission, in the Companys press
releases and in oral statements, words such as may, will, expect, anticipate, continue,
estimate, project, believes or similar expressions are intended to identify forward-looking
statements within the meaning of the Act and are included, along with this statement, for purposes
of complying with the safe harbor provision of the Act. 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.
    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 business 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 of this
business. This business 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
polyvinyl chloride (PVC) resin. 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. For a further discussion of other risk factors and cautionary statements, refer to Risk
Factors and Cautionary Statements That May Affect Future Results and Critical Accounting
Policies Involving Significant Estimates on pages 25 through 31 of the Companys 2004 Annual
Report to Shareholders, filed as an Exhibit hereto. These factors are in addition to any other
cautionary statements, written or oral, which may be made or referred to in connection with any
such forward-looking statement or contained in any subsequent filings by the Company with the
Securities and Exchange Commission. 23




---



##### Table of Contents



Item 2. PROPERTIES The Coyote Station, which commenced operation in 1981, is a 414,000 kw (nameplate rating)
mine-mouth plant located in the lignite coal fields near Beulah, North Dakota and is jointly owned
by the Utility, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern
Public Service Company. The Utility owns 35% of the plant and on July 1, 1998 became the operating
agent of the Coyote Station. The Utility, jointly with Northwestern Public Service Company and Montana-Dakota Utilities
Co., owns the 414,000 kw (nameplate rating) Big Stone Plant in northeastern South Dakota which commenced operation in 1975. The Utility is the operating
agent of Big Stone Plant and owns 53.9% of the plant. Located near Fergus Falls, Minnesota, the Hoot Lake Plant is comprised of three separate
generating units with a combined nameplate rating of 127,000 kw. The oldest Hoot Lake Plant
generating unit was constructed in 1948 (7,500 kw nameplate rating) and a subsequent unit was added
in 1959 (53,500 kw nameplate rating). A third unit was added in 1964 (66,000 kw nameplate rating)
and later modified during 1988 to provide cycling capability, allowing this unit to be more
efficiently brought online from a standby mode. At December 31, 2004 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;
796 miles of 115 kv lines; and 4,046 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. Management of the Company believes the facilities and equipment described above are adequate
for the Companys present businesses. All of the common shares of the companies owned by Varistar are pledged to secure indebtedness
of Varistar. 
 Item 3. LEGAL PROCEEDINGS Not Applicable. 
 Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the three months ended December
31, 2004. 
 Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 2005) 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. 24




---



##### Table of Contents



DATES ELECTEDNAME AND AGE
    
    TO OFFICE
    
    PRESENT POSITION AND BUSINESS EXPERIENCEJohn D. Erickson (46)
    
    4/8/02
    
    Present: President and Chief Executive Officer4/9/01

    
    President4/10/00
    
    Executive Vice President, Chief Financial Officer and TreasurerPrior to4/10/00
    
    Vice President, Finance and Chief Financial OfficerGeorge A. Koeck (52)
    
    4/10/00
    
    Present: Corporate Secretary and General CounselPrior to4/10/00
    
    General CounselLauris N. Molbert (47)
    
    6/10/02
    
    Present: Executive Vice President and Chief Operating Officer4/9/01
    

Executive
Vice President, Corporate Development and Varistar President and
Chief Operating Officer4/10/00
    
    Vice President, Chief Operating Officer, VaristarPrior to4/10/00
    
    Varistar President and Chief Operating OfficerKevin G. Moug (45)
    
    4/9/01
    
    Present: Chief Financial Officer and TreasurerPrior to4/9/01
    
    Varistar Chief Financial Officer and TreasurerCharles S. MacFarlane (40)
    
    5/1/03
    
    President, Otter Tail Power Company6/1/02
    
    Interim President, Otter Tail Power Company1/29/02
    
    Director, Finance & Strategic
Planning, Otter Tail Power Company12/1/01
    
    Director, Finance Planning, Otter Tail Power CompanyPrior to12/2/01
    
    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. 25




---



##### Table of Contents



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 56, to Selected Consolidated Financial Data on
Page 17 and to Quarterly Information on Page 53 of the Companys 2004 Annual Report to
Shareholders, filed as an Exhibit hereto. 
  Item 6.
    SELECTED FINANCIAL DATA The information required by this Item is incorporated by reference to Selected Consolidated
Financial Data on Page 17 of the Companys 2004 Annual Report to Shareholders, filed as an Exhibit
hereto. 
  Item 7.
    MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS The information required by this Item is incorporated by reference to Managements Discussion
and Analysis of Financial Condition and Results of Operations on Pages 18 through 32 of the
Companys 2004 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 27 through 29 of the Companys 2004 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 53, the Companys audited financial statements on Pages 34 through 53 and Report of
Independent Registered Public Accounting Firm on page 33 of the Companys 2004 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) as of December 31, 2004, the end of the period covered
by this report. Based on that evaluation, the Chief Executive 26




---



##### Table of Contents



Officer and Chief Financial Officer concluded that the Companys disclosure controls and procedures
were effective as of December 31, 2004. During the fiscal quarter ended December 31, 2004 there were no changes in the Companys
internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act)
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 2004 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 33
of the Companys 2004 Annual Report to Shareholders, filed as an Exhibit hereto. 
  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
7, 2005. The information regarding executive officers is set forth in Item 4A hereto. The
information regarding Section 16 reporting is incorporated by reference to the information under
Section 16(a) Beneficial Ownership Reporting Compliance in the Companys definitive Proxy
Statement dated March 7, 2005. The information regarding Audit Committee financial experts and
identification of the Audit Committee 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 7, 2005. 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 10 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
Summary Compensation Table, Options/SAR Grants in Last Fiscal Year, Aggregated Option/SAR
Exercises in Last Fiscal Year and Fiscal Year-End Options/SAR Values, Long-Term Incentive Plan
Awards in Last Fiscal Year, Pension and Supplemental Retirement Plans, Severance and Employment
Agreements, and Director Compensation in the Companys definitive Proxy Statement dated March 7,
2005. 27




---



##### Table of Contents



Item 12.
    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS The security ownership information set forth under Outstanding Voting Shares and
Managements Security Ownership in the Companys definitive Proxy Statement dated March 7, 2005
is incorporated herein by reference. EQUITY COMPENSATION PLAN INFORMATION The following table sets forth information as of December 31, 2004 about the Companys common
stock that may be issued under all of its equity compensation plans: Number ofsecuritiesremaining availableNumber of
    
    
    
    
    
    
    for future issuancesecurities to be
    
    
    
    
    
    
    under equityissued upon
    
    
    Weighted-average
    
    
    compensation plansexercise of
    
    
    exercise price of
    
    
    (excludingoutstanding
    
    
    outstanding
    
    
    securitiesoptions, warrants
    
    
    options, warrants
    
    
    reflected in columnPlan Category
    
    and rights
    
    
    and rights
    
    
    (a))(a)
    
    
    (b)
    
    
    (c)Equity
compensation plans
approved by
security holders1999 Stock
Incentive Plan
    
    
    1,555,277
    (1)
    
    $
    25.35
    
    
    
    524,638
    (2)1999 Employee
Stock Purchase Plan
    
    
    
    
    
    
    N/A
    
    
    
    98,079
    (3)Equity compensation
plans not approved
by security holders
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    1,555,277
    
    
    $
    25.35
    
    
    
    622,717
   (1)
    Includes 47,000 performance based share awards made in 2004 and excludes 128,417 shares of
restricted stock issued under the 1999 Stock Incentive Plan.(2)
    The 1999 Stock Incentive Plan provides for the issuance of any shares available under the
plan in the form of restricted stock, performance awards and other types of stock-based
awards, in addition to the granting of options, warrants or stock appreciation rights.(3)
    Shares are issued based on employees election to participate in the plan. 
  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 in the Companys definitive Proxy
Statement dated March 7, 2005. 28




---



##### Table of Contents



PART IV 
  Item 15.
    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES  (a)
    List of documents filed:  (1)
    and (2) See Table of Contents on Page 30 hereof.(3)
    See Exhibit Index on Pages 31 through 37 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. 
 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 CORPORATIONBy
    
    /s/ Kevin G. MougKevin G. Moug
     Chief Financial Officer and
TreasurerDated: March 14, 2005
 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 TitleJohn 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. EricksonChairman of the Board and Director
    
    )
    
    
    
    Pro Se and Attorney-in-Fact)
    
    
    
    Dated March 14, 2005Karen 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
    
    )
 29




---



##### Table of Contents



OTTER TAIL CORPORATION TABLE OF CONTENTS FINANCIAL STATEMENTS, SUPPLEMENTARY FINANCIAL DATA, SUPPLEMENTAL FINANCIAL SCHEDULES INCLUDED IN
ANNUAL REPORT (FORM 10-K) FOR THE YEAR ENDED
DECEMBER 31, 2004 The following items are included in this annual report by reference to the registrants Annual
Report to Shareholders for the year ended December 31, 2004: Page inAnnualReport toShareholdersFinancial Statements:Report of Independent Registered Public Accounting Firm
    
    
    33Consolidated Balance Sheets, December 31, 2004 and 2003
    
    
    34 & 35Consolidated Statements of Income for the Three Years
Ended December 31, 2004
    
    
    36Consolidated Statements of Common Shareholders Equity for the
Three Years Ended December 31, 2004
    
    
    37Consolidated Statements of Cash Flows for the Three Years
Ended December 31, 2004
    
    
    38Consolidated Statements of Capitalization, December 31, 2004
and 2003
    
    
    39Notes to Consolidated Financial Statements
    
    
    40-53Selected Consolidated Financial Data for the Five Years
Ended December 31, 2004
    
    
    17Quarterly Data for the Two Years Ended
December 31, 2004
    
    
    53
 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. 30




---



##### Table of Contents



Exhibit Index
to
Annual Report
on Form 10-K
For Year Ended December 31, 2004 Previously FiledAsExhibitFile 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
    
    333-90952
    
    
    99-A-1
    
    
    Credit Agreement dated as of
April 30, 2002.4-D-7
    
    8-K filed
9/27/02
    
    
    99-A
    
    
    First Amendment dated as of
September 19, 2002 to Credit
Agreement dated as of April 30, 2002.4-D-8
    
    10-Q for quarter
ended 6/30/03
    
    
    4-A
    
    
    Second Amendment dated as of
April 29, 2003 to Credit
Agreement dated as of April 30, 2002.4-D-9
    
    10-Q for quarter
ended 9/30/03
    
    
    4.1
    
    
    Third Amendment dated as of
August 25, 2003 to Credit
Agreement dated as of April 30, 2002.4-D-10
    
    10-Q for quarter
ended 3/31/04
    
    
    4.1
    
    
    Fourth Amendment dated as of
April 28, 2004 to Credit
Agreement dated as of April 30, 2002.4-D-11
    
    10-Q for quarter
ended 9/30/04
    
    
    4.1
    
    
    Fifth Amendment dated as of
October 28, 2004 to Credit
Agreement dated as of April 30, 2002.
 -31-




---



##### Table of Contents



Previously FiledAsExhibitFile No.
    
    No.4-D-12
    
    333-116206
    
    
    4.12
    
    
    Credit Agreement dated as of
August 13, 2004 among the Company,
the banks party thereto, UBS Securities
LLC, as Arranger and UBS AG, Stamford
Branch, as Agent.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.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.
 -32-




---



##### Table of Contents



Previously FiledAsExhibitFile No.
    
    No.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, 1993.10-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 North-
western 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).
 -33-




---



##### Table of Contents



Previously FiledAsExhibitFile No.
    
    No.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 StonePlant(dated as of July 22, 2004).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.
 -34-




---



##### Table of Contents



Previously FiledAsExhibitFile No.
    
    No.10-H-4
    
    10-K for year
ended 12/31/92
    
    
    10-H-4
    
    
    Agreement dated as of Sept.
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.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-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).
 -35-




---



##### Table of Contents



Previously FiledAsExhibitFile No.
    
    No.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).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-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.*10-O-3
    
    10-Q for quarter
ended 6/30/02
    
    
    10-C
    
    
    Executive Employment Agreement,
Kevin Moug.*
 -36-




---



##### Table of Contents



Previously FiledAsExhibitFile No.
    
    No.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 6/03/02
    
    10-E
    
    Change in Control Severance
Agreement, John Erickson.*10-P-2
    
    10-Q for quarter
ended 6/03/02
    
    10-F
    
    Change in Control Severance
Agreement, Lauris Molbert.*10-P-3
    
    10-Q for quarter
ended 6/03/02
    
    10-G
    
    Change in Control Severance
Agreement, Kevin Moug.*10-P-4
    
    10-Q for quarter
ended 6/03/02
    
    10-H
    
    Change in Control Severance
Agreement, George Koeck.*13-A
    
    
    
    
    
    Portions of 2004 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. -37-