-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, D136XRGCXEfyDHMb5nDzbHDUExkcBhl763nAGG9st/sfP15DCjRRQgh4ztUvKFS6 i/1J8Jb7WLHWSz8C3ScnJQ== 0000075129-00-000005.txt : 20000411 0000075129-00-000005.hdr.sgml : 20000411 ACCESSION NUMBER: 0000075129-00-000005 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 11 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000329 FILER: COMPANY DATA: COMPANY CONFORMED NAME: OTTER TAIL POWER CO CENTRAL INDEX KEY: 0000075129 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 410462685 STATE OF INCORPORATION: MN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 000-00368 FILM NUMBER: 581642 BUSINESS ADDRESS: STREET 1: 215 S CASCADE ST STREET 2: PO BOX 496 CITY: FERGUS FALLS STATE: MN ZIP: 56538-0496 BUSINESS PHONE: 2187398200 10-K405 1 10-K FOR 1999 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) (X) Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1999 OR ( ) Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from _______ to _______ Commission File Number 0-368 OTTER TAIL POWER COMPANY (Exact name of registrant as specified in its charter) MINNESOTA 41-0462685 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 215 S. CASCADE ST., BOX 496, FERGUS FALLS, MN 56538-0496 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (218) 739-8200 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered NONE NONE Securities registered pursuant to Section 12(g) of the Act: COMMON SHARES, par value $5.00 per share PREFERRED SHARE PURCHASE RIGHTS CUMULATIVE PREFERRED SHARES, without par value (Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. (Yes X No ) Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (X) State the aggregate market value of the voting stock held by nonaffiliates of the registrant. $438,940,176 as of February 29, 2000 Indicate the number of shares outstanding of each of the registrant's classes of Common Stock, as of the latest practicable date (adjusted to reflect the two-for-one stock split effective March 15, 2000): 23,849,974 Common Shares ($5 par value) as of February 29, 2000. Documents Incorporated by Reference: 1999 Annual Report to Shareholders-Portions incorporated by reference into Parts I and II Proxy Statement dated March 10, 2000-Portions incorporated by reference into Part III PART I Item 1. BUSINESS -------- (a) General Development of Business ------------------------------- Otter Tail Power Company (the Company) is an operating public utility incorporated in 1907 under the laws of the State of Minnesota. The Company's principal executive office is located at 215 South Cascade Street, Box 496, Fergus Falls, Minnesota 56538-0496; its telephone number is (218) 739-8200. Historically, the Company's primary business has been the production, transmission, distribution and sale of electric energy. During the last decade the Company, through its subsidiaries, has made significant investments in other businesses which are referred to as Manufacturing Operations, Health Services Operations and Other Business Operations. Manufacturing Operations includes businesses involved in the production of polyvinyl chloride (PVC) pipe, agricultural equipment, frame-straightening equipment and accessories for the auto body shop industry, contract machining, and metal parts stamping and fabrication. Health Services Operations consists of certain businesses which are involved in the sale, service, rental, refurbishing, and operation of medical imaging equipment and the sale of related supplies and accessories to various medical institutions. Other Business Operations include businesses involved in such areas as electrical and telephone construction contracting, transportation, telecommunications, entertainment, energy services, and natural gas marketing. Substantially all of these businesses are owned by the Company's wholly owned subsidiary Varistar Corporation (Varistar). The Company continues to investigate acquisitions of additional non-electric businesses and expects continued growth in this area. On September 1, 1999 the Company acquired the flatbed trucking operations of E. W. Wylie Corporation (Wylie). Wylie is located in Fargo, North Dakota and operates in 48 states and 6 Canadian provinces. Effective January 1, 2000 the Company acquired the assets and operations of Vinyltech Corporation (Vinyltech) located in Phoenix, Arizona. Vinyltech is a manufacturer of PVC pipe. In August 1999, as part of an agreement with the Minnesota Pollution Control Agency (MPCA), the Company donated the assets of the Quadrant Co. municipal waste burning facility to the City of Perham, Minnesota. On October 1, 1999 the Company completed the sale of certain assets of the radio stations and video production company owned by KFGO, Inc. and the radio stations owned by Western Minnesota Broadcasting Company. See "Other Business Operations" for additional information regarding these subsidiaries. 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 20 through 26 of the Company's 1999 Annual Report to Shareholders, filed as an Exhibit hereto. (b) Financial Information About Industry Segments --------------------------------------------- The Company and its subsidiaries are engaged in businesses that have been classified into four segments: Electric Operations, Manufacturing Operations, Health Services Operations, and Other Business Operations. Financial information about the Company's industry segments is incorporated by reference to note 4 of "Notes to consolidated financial statements" on pages 36 and 37 of the Company's 1999 Annual Report to Shareholders, filed as an Exhibit hereto. (c) Narrative Description of Business --------------------------------- ELECTRIC OPERATIONS ------------------- General - ------- The Company derived 50 percent of its consolidated operating revenues from the electric segment in 1999; 53 percent in 1998; and 51 percent in 1997. In 1999 the Company derived approximately 50.8 percent of its retail electric revenues from Minnesota, 41.3 percent from North Dakota, and 7.9 percent from South Dakota. The territory served by the Company is predominantly agricultural, including a part of the Red River Valley. Although there are relatively few large customers, sales to commercial and industrial customers are significant. By customer category, 30.8 percent of 1999 electric revenue was derived from commercial customers, 28.2 percent from residential customers, 17.4 percent from industrial customers, and 23.6 percent from other sources, including municipalities, farms and power pools. No customer accounted for more than 10 percent of electric revenues in 1999. Power pool sales to other utilities, which accounted for 26.3 percent of total 1999 kwh sales, increased from 25.5 percent in 1998. Hot summer weather in the Midwest and North Central regions of the United States, combined with increased emphasis on power marketing efforts and increased generation at the Company's plants contributed to the increase in power pool revenues. Activity in short-term energy sales is subject to change based on a number of factors and the Company is unable to predict the 2000 level of activity. The aggregate population of the Company's retail electric service area is approximately 230,000. In this service area of 423 communities and adjacent rural areas and farms, approximately 123,600 people live in communities having a population of more than 1,000, according to the 1990 census. The only communities served which have a population in excess of 10,000 are Jamestown, North Dakota (15,571); Fergus Falls, Minnesota (12,362); and Bemidji, Minnesota (11,245). Since 1990 when the customer count was at a low of 121,277, the Company has experienced an increase in customers. By year end 1999 total customers had increased to 126,292. During 1999, the Company experienced a net increase of 580 customers, with the majority of growth in residential customers. Competition - ----------- The Company's 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. The Company's 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 Company may also face competition as the restructuring of the electric industry evolves. Proposals that are being considered by various states and at the federal level, along with the National Energy Policy Act of 1992 (NEPA), are expected to bring more competition into the electric industry. NEPA reduces restrictions on operation and ownership of independent power producers (IPPs). It also allows IPPs and other wholesale suppliers and purchasers increased access to transmission lines. In 1996, FERC issued two closely related final rules. FERC Order No. 888 opened wholesale power sales to competition by requiring public utilities who own, control, or operate transmission lines, to file nondiscriminatory pro forma open access tariffs that offer others the same transmission service they provide themselves. FERC Order No. 889 requires utilities to post or make available information about their transmission system for their own wholesale power transactions, such as capacity availability, by the same means as their competitors would via an Open Access Same-time Information System (OASIS), as well as separate their wholesale marketing and transmission operation functions. As the electric industry moves towards deregulation, the Company expects the industry to become more competitive. The Company is taking a number of steps to position itself for success in a competitive marketplace. The Company has functionally unbundled its energy supply, energy delivery, and energy services operations. Necessary accounting systems have been developed to capture costs and determine the profitability of each of these business units and to identify areas for improvement and opportunities for increased profitability. Separate business plans have been created for each business unit. The Company has established an energy services business unit to promote the energy-related products and services traditionally offered to the Company's customers and to develop new products and services to be offered to current and potential customers in order to distinguish the Company for competition. The Company offered a voluntary early retirement program in 1998 that reduced the electric utility staff by 55 employees. Furthermore, with the goal of alleviating state tax inequities in the electric industry, the Company is working with other utilities to develop tax reform proposals and testimony for legislative committees studying competition in Minnesota and North Dakota. As the electric industry evolves and becomes more competitive, the Company believes it is well positioned to be successful. The Company's generation capacity appears poised for competition due to unit heat rate improvements and reductions in fuel and freight costs. A comparison of the Company's electric retail rates to the rates of other investor-owned utilities, cooperatives, and municipals in the states the Company serves indicates that the Company's rates are competitive. In addition, the Company plans to attempt more flexible pricing strategies under an open, competitive environment. For the status of other regulatory initiatives relating to competition, see "General Regulation". Capability and Demand - --------------------- At December 31, 1999, the Company had base load net plant capability totaling 566,593 kw, consisting of 254,731 kw from the jointly-owned Big Stone Plant (constituting the Company's 53.9 percent share of the plant's total capability), 156,825 kw from the Hoot Lake Plant, 149,450 kw from the jointly- owned Coyote Station (constituting the Company's 35 percent share of the station's total capability), and, under contract, 5,587 kw from a co- generation plant near Bemidji, Minnesota. In addition to its base load capability, the Company has combustion turbine and small diesel units, used chiefly for peaking and standby purposes, with a total capability of 91,175 kw, and hydroelectric capability of 3,991 kw. During 1999, the Company generated about 66 percent of its total kwh sales and purchased the balance. The Company has made arrangements to help meet its future base load requirements, and continues to investigate other means for meeting such requirements. The Company has an agreement with another utility for the annual exchange of 75,000 kw of seasonal capacity which runs through October 2004. The Company 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 from May 1, 2000 to April 30, 2010. The Company also has seasonal capacity agreements for the summers of 2000, 2001 and 2002. The Company has a direct control load management system, which provides some flexibility to the Company to effect reductions of peak load. The Company, in addition, offers rates to customers which encourage off-peak usage. The Company is a member of the Mid-Continent Area Power Pool (MAPP). The objective of MAPP is to coordinate the planning and operation of generation and interconnecting transmission facilities to provide reliable and economic electric service to members' customers. Customers served by MAPP members may, therefore, benefit from the regional high voltage interconnections, which are capable of transferring large blocks of energy between systems. Also, high voltage interconnections permit companies to engage in power transactions with each other. The operating agreement for MAPP was restated in 1996 to open membership to organizations outside the original Upper Midwest boundaries, to establish a Regional Transmission Group and to add energy market functions. In December 1999 the Federal Energy Regulatory Commission issued Order No. 2000. This order requires public utilities that own, operate or control interstate transmission to file by October 15, 2000 a proposal for a regional transmission organization (RTO) or a description of any efforts made to participate in an RTO, the reasons for not participating, and any plans for further work towards participation. The Company, along with several other companies and MAPP, are working with the Midwest Independent System Operator (MISO) to become a part of MISO and to be compliant with Order No. 2000. The Company traditionally experiences its peak system demand during the winter season. For the calendar year 1999, the Company experienced a system peak demand of 628,259 kw on January 13, 1999. The Company's highest sixty- minute peak demand ever was 635,529 kw on January 7, 1997. Taking into account additional capacity available to it in January 1999 under power purchase contracts (including short-term arrangements), as well as its own generating capacity, the Company's capability of then meeting system demand, including reserve requirements computed in accordance with accepted industry practice, amounted to 787,593 kw. The Company expects moderate load growth in peak demand in 2000 as compared to 1999. The Company's additional capacity available under power purchase contracts (as described above), combined with the Company's generating capability and load management control capabilities, is expected to meet 2000 system demand, including industry reserve requirements. Fuel Supply - ----------- Coal is the principal fuel burned by the Company at its Big Stone, Coyote, and Hoot Lake generating plants. Coyote, a mine-mouth facility, burns North Dakota lignite coal. Hoot Lake and Big Stone plants burn western subbituminous coal. The following table shows, for 1999, the sources of energy used to generate the Company's net output of electricity: Net Kilowatt % of Total Hours Kilowatt Generated Hours Sources (Thousands) Generated ------- ----------- --------- Subbituminous Coal. . . . . . . . . . . 2,485,191 70.1% Lignite Coal. . . . . . . . . . . . . . 1,027,045 29.0 Hydro . . . . . . . . . . . . . . . . . 25,035 .7 Oil . . . . . . . . . . . . . . . . . . 8,777 .2 --------- ----- Total . . . . . . . . . . . . . . . . . 3,546,048 100.0% ========= ===== The Company has a primary coal supply agreement with Kennecott Energy Company for the supply of subbituminous coal to Big Stone Plant for 2000 and 2001. The coal comes from the Cordero Rojo Complex in Campbell County, Wyoming. The Company is in final negotiations for the supply of subbituminous coal as needed for the Hoot Lake Plant. A lignite coal contract with Knife River Coal Mining Company for the Coyote Station expires in 2016, with a 15-year renewal option subject to certain contingencies. Knife River Coal Mining Company is an affiliate of Montana-Dakota Utilities Co., which is a co-owner of the Big Stone Plant and Coyote Station. In September 1996, three of the four co-owners of the Coyote Station filed a Demand and Notice of Arbitration complaint against Knife River Coal Mining Company and MDU Resources Group, Inc. The three co-owners contended that the 15-year-old pricing mechanism outlined in the original coal supply contract had been abandoned by all parties over the past 8 years and no longer resulted in fair, equitable, and competitive prices for the lignite coal used to generate electricity at the plant. During 1999 settlement of the arbitration resulted in (1) a reduction of fuel prices for Coyote Station, beginning March 26, 1999, (2) modification of the price adjustment provision of the contract for the future, and (3) a requirement that Knife River refund excess amounts paid for coal delivered from September 13, 1996 through March 26, 1999. The Company received a refund of $2.7 million, representing its share as a co-owner of Coyote Station. This refund and accumulated interest has been recorded as a liability pending the outcome of regulatory filings in each state to determine procedures for refunds to electric retail customers. The regulatory filings include a request to recover arbitration costs incurred by the Company. Responses to the Company's regulatory filings are expected by mid-2000. It is the Company's practice to maintain minimum 30-day inventory (at full output) of coal at the Big Stone Plant, a 20-day inventory at the Coyote Station, and a 10-day inventory at the Hoot Lake Plant. The Company has two coal transportation agreements with The Burlington Northern and Santa Fe Railway Company. The first agreement is for transportation services to the Big Stone Plant which runs through 2001. The second agreement is for Hoot Lake Plant which expires in mid-2004. No coal transportation agreement is needed for the Coyote Station due to its location next to a coal mine. The average cost of coal consumed (including handling charges to the plant sites) per million BTU for each of the three years 1999, 1998, and 1997, was $.956, $.960, and $.957, respectively. The Company is permitted by the State of South Dakota to burn some alternative fuels, including tire and refuse derived fuel, at the Big Stone Plant. The quantity of alternative fuel burned at the Big Stone Plant is insignificant when compared to the total annual coal consumption at the Big Stone Plant. Rate Regulation - --------------- The Company is subject to electric rate regulation as follows: Year Ended December 31, 1999 ----------------- % of Electric % of kwh Rates Regulation Revenues Sales ----- ---------- -------- -------- MN retail sales MN Public Utilities Commission 40.5% 38.1% ND retail sales ND Public Service Commission 33.0 30.0 SD retail sales SD Public Utilities Commission 6.3 5.6 Transmission & sales FERC for resale 20.2 26.3 ----- ----- 100.0% 100.0% ===== ===== The Company has obtained approval from the regulatory commissions in all three states which it serves for lower rates for residential demand control and controlled service, in Minnesota and North Dakota for real-time pricing, and in North Dakota and South Dakota for bulk interruptible rates. Each of these special rates is designed to improve efficient use of Company facilities, while encouraging use of cost-effective electricity instead of other fuels and giving customers more control over the size of their electric bill. All of the Company's electric rate schedules now in effect, except for wheeling, certain municipal and area lighting services and certain interruptible rates, provide for adjustments in rates based upon the cost of fuel delivered to the Company's generating plants, as well as for adjustments based upon the cost of electric power energy purchased by the Company. Such adjustments are presently based upon a two-month moving average in Minnesota and under FERC regulation, a three-month moving average in South Dakota, and a four-month moving average in North Dakota and are applied to the next billing after becoming applicable. The following summarizes the electric rate proceedings since January 1, 1995 and describes the procedures for rate requests with the Minnesota Public Utilities Commission (MPUC), the South Dakota Public Utilities Commission (SDPUC), the North Dakota Public Service Commission (NDPSC) and FERC: Minnesota: On July 21, 1999, the MPUC approved the Company's 1998 financial incentive filing, which included the recovery of associated lost margins and financial incentives of $1,829,000 from implementing conservation programs and performance in meeting energy savings goals. The MPUC indicated its intention to review the ongoing role of financial incentives for utility investments in conservation. Due to the uncertain future of financial incentives, no accrual was made for the 1999 financial incentives. On January 27, 2000, the MPUC approved a new Shared-Savings DSM Financial Incentive Plan for 1999 and 2000, which awards utilities a small share of the total benefits from investments in conservation. Since 1995, the Company has recovered demand-side management related costs, under Minnesota's Conservation Improvement Programs, through the use of an annual recovery mechanism approved by the MPUC. In 1999, the MPUC approved a 1.5 percent surcharge on all Minnesota customers' bills starting on July 1, 1999, for the recovery of conservation-related costs over and above those being recovered in current rates. The previous 12-month period surcharge was 2.75 percent. The current surcharge rate will be in place until June 30, 2000 when it will be revised for subsequent years' program results. The Company has not had a significant rate proceeding before the MPUC since July 1987. Under Minnesota law, the MPUC must allow implementation of an interim rate increase, subject to refund with interest, sixty days after the initial filing date of a rate increase request, except that the MPUC is not required to allow implementation of the interim rate increase until four months after the effective date of a previous rate order. The amount of the interim rate increase will be calculated using the proposed test year cost of capital, the rate of return on common equity most recently granted to the Company by the MPUC, and rate base and expense items allowed by a currently effective MPUC order. In addition, if the MPUC fails to make a final determination regarding any rate request within ten months after the initial request is filed, then the requested rate is deemed to be approved, except if (1) an extension of the procedural schedule (in case of a contested rate increase request) has been granted, in which case the schedule of rates will be deemed to have been approved by the MPUC on the last day of the extended period of suspension of the rate increase, or (2) a settlement has been submitted to and rejected by the MPUC, and the MPUC does not make a final determination concerning the schedule of rates, in which case the schedule of rates will be deemed to have been approved sixty days after the initial or, if applicable, the extended period of suspension of the rate increase. North Dakota: On October 6, 1999, the NDPSC approved a settlement agreement following an audit of the Company's electric operations in North Dakota. The effect of this settlement decreased 1999 earnings by approximately $441,000 after taxes or $0.02 per share. As part of the settlement the Company is required to refund to North Dakota customers any 1999 regulated electric operations earnings from North Dakota over a 12.5 percent return on equity. While the final decision on any potential refund relating to 1999 lies with the NDPSC, the Company expects that any refund will not be significant. In addition, as part of the settlement agreement, the Company filed a proposal for a performance-based ratemaking plan in 2000. Rate requests filed with the NDPSC become effective thirty days after the date of filing unless suspended by the NDPSC. Within seven months after the date of suspension, the NDPSC must act on the request, and during the period of consideration by the NDPSC a suspended rate can be implemented only with the approval of the NDPSC. The NDPSC periodically performs audits of gas and electric utilities over which it has rate setting jurisdiction to determine reasonability of overall rate levels. In the past, these audits have occasionally resulted in settlement agreements adjusting rate levels. South Dakota: There have been no significant rate proceedings in South Dakota since November 1987. Under South Dakota law a requested rate increase can be implemented thirty days after the date of filing, unless its effectiveness is suspended by the SDPUC. The SDPUC may suspend the effectiveness of the proposed rate change for a period not longer than ninety days beyond the time when the rate change would otherwise go into effect, unless the SDPUC finds that a longer time is required, in which case the SDPUC may extend the suspension for a period not to exceed a total of twelve months. A public utility may not put a proposed rate change into effect until at least forty-five days after the SDPUC has made a determination concerning any previously filed rate change. In the event that a requested rate change is suspended by the SDPUC, such requested rate change may be implemented by the public utility six months after the date of filing (unless previously authorized by the SDPUC), subject to refund with interest. FERC: The Company's wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935, as amended (FPA). Filed rates are effective after a one-day suspension period, subject to ultimate approval by the FERC. Power pool sales are conducted continuously through MAPP in accordance with schedules filed by MAPP with the FERC. On March 25, 1997, FERC issued an order approving a settlement agreement in the Company's Open Access Transmission Tariff filing of July 9, 1996. This settlement sets the rates the Company can charge under its Open Access Transmission Tariff. On May 29, 1997, FERC issued an order approving a request for the waiver of the standards of conduct under Order 889. General Regulation - ------------------ Minnesota: Under the Minnesota Public Utilities Act, the Company 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 Department of Commerce (DOC), formerly Department of Public Service, 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 conserva- tion. The DOC acts as a state advocate in matters heard before the MPUC. The DOC also has the power to prepare and adopt regulations to conserve and allocate energy in the event of energy shortages and on a long-term basis. Under Minnesota law, every 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 percent of its gross operating revenues from service provided in Minnesota. The DOC may require the Company to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such DOC orders are appealable to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. In 1995, the MPUC approved an automatic recovery mechanism which allows the Company to collect from customers any conservation-related expenditures not included in base rates. 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 Company's most recent plan was submitted to the MPUC in 1999, and was approved, without modifications, early in 2000. The MPUC ordered the Company to complete a study on the feasibility of offering its customers a green pricing program. Under green pricing, customers may voluntarily choose to pay more per kilowatt-hour for energy generated by renewable resources. The green pricing study is to be filed with the MPUC no later than July 1, 2001. The MPUC also granted the Company a one-year waiver in submitting its next integrated resource plan, which will be completed in 2002. 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. The 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 in Minnesota sites for new electric power generating plants (50,000 kw or more) and routes for transmission lines (200 kv or more) and to certify such sites and routes as to environmental compatibility. North Dakota: The Company is subject to the jurisdiction of the NDPSC with respect to rates, services, certain issuances of securities and other matters. 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 affects new electric power generating plants of 50,000 kw or more and new transmission lines of more than 115 kv. The Company is required to submit a ten-year plan to the NDPSC annually. South Dakota: The South Dakota Public Utilities Act subjects the Company to the jurisdiction of the SDPUC with respect to rates, public utility services, establishment of assigned service areas, and other matters. The Company is currently exempt from 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. FERC: The Company is also subject to regulation by the FERC, successor to the Federal Power Commission, created pursuant to the FPA. The FERC is an independent agency which has jurisdiction over rates for sales for resale, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. General: The United States Congress ended its 1999 legislative session without taking action on proposed electric industry restructuring legislation. The Company expects that during 2000 Congress will continue to debate proposed legislation which, if enacted, would promote customer choice and a more competitive electric market. The MPUC issued its Wholesale Competition Report in 1996 and its Retail Competition Report in 1997 and continues to work on specific topics in the areas of potential stranded costs, unbundled rates and affiliated transactions. The Minnesota legislature did not take any significant legislative action on electric utility restructuring in 1999, and no significant action is expected during 2000. However, the DOC plans to draft comprehensive retail access legislation that could be introduced in early 2001. Company personnel have been actively involved in working with the DOC-sponsored work groups and a legislative task force. The Minnesota State Chamber of Commerce introduced legislation in 2000 relating to the separation of costs for generation, transmission and distribution on electric service statements. In 1997, the North Dakota legislature created a subcommittee to investigate the impact of electric utility industry restructuring on North Dakota. The North Dakota legislature plans to deal first with tax issues surrounding restructuring. Currently, South Dakota is not undertaking any legislative activity regarding electric utility restructuring. The Company 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 Company is unable to predict the impact on its operations resulting from future regulatory activities by any of the above agencies, from any future legislation or from any future tax that may be imposed upon the source or use of energy. Environmental Regulation - ------------------------ Impact of Environmental Laws: The Company'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 Company estimates that it has expended in the five years ended December 31, 1999, approximately $2,565,000 for environmental control facilities. Included in the 2000-2004 construction budget are approximately $5,065,000 for environmental equipment for existing and new facilities, including $276,000 for 2000. 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. All primary fuel burned by the Company at its steam generating plants is North Dakota lignite or western subbituminous coal. Electrostatic precipitators have been installed at the principal units at the Hoot Lake Plant and at the Big Stone 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 Big Stone Plant and the Hoot Lake Plant currently meet all presently applicable federal and state air quality and emission standards. The Coyote Station is substantially the same design as the Big Stone Plant, except for site-related items and the inclusion of 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 without producing sludge, an unwanted by-product of a conventional wet scrubber system. 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 oxide (NOx). The national SO2 emission reduction goals are achieved through a new market-based system under which power plants are allocated "emissions allowances" that will require plants to either reduce their emissions or acquire allowances from others to achieve compliance. The SO2 emission reduction requirements were imposed in two phases. Phase one was imposed in 1995 and phase two was imposed in 2000. The phase one requirements did not apply to any of the Company's plants. The phase two requirements will apply to the Company's plants. The Company believes that its current use of low sulfur coal at the Hoot Lake Plant and the dry scrubbers installed at the Coyote Station will enable the facilities to comply with anticipated phase two limitations on SO2 emissions. The subbituminous coal burned at the Big Stone Plant replaced lignite, which had been used since inception of plant operation in 1975 as the primary fuel. The Company intends that the Big Stone Plant will maintain current levels of operation and meet phase two requirements by burning low sulfur subbituminous coal. The national NOx emission reduction goals are to be achieved by imposing mandatory emissions standards on individual sources. The NOx emissions regulations that were issued by the EPA in 1995 apply to phase one boilers of the same design as those used at the Hoot Lake Plant units 2 and 3. The Act allowed the EPA to retain the standard as it currently applies to phase one boilers or adopt more stringent standards for phase two boilers by January 1, 1997. The EPA adopted more stringent standards on December 19, 1996. The Company had the option of complying with the phase one standards beginning on January 1, 1997, under EPA's early opt-in provision, or complying with any revised standard for phase two boilers. The Company elected the early opt-in provision for Hoot Lake Plant unit 2. The unit is governed by the phase one standard until January 1, 2008. The Company did not elect the early opt-in provision for Hoot Lake Plant unit 3. Installation of low-NOx equipment was completed on Hoot Lake Plant unit 3 to meet the NOx emission requirements. On December 19, 1996, the EPA also adopted NOx emissions regulations that would be applicable to cyclone-fired boilers such as those used at the Big Stone Plant and Coyote Station. The regulations require that the emission standard be met by cyclone boilers beginning on January 1, 2000. The Company has evaluated the Big Stone Plant and Coyote Station NOx emissions with respect to the December 19, 1996 rules. Existing emissions monitoring data indicate that the Coyote Station meets the emissions requirements. During 1997, the Company conducted tests at the Big Stone Plant to determine if emissions can be reduced through modifications to existing equipment. The results of the tests were positive and modifications have been completed. As a result of the modifications, the Company believes the NOx emissions regulations have been met. The Act contains a list of regulated toxic air pollutants, which includes certain substances believed to be emitted by the Company's plants. The Act calls for EPA studies of the effects of emissions of the listed pollutants by electric utility steam generating plants. The EPA has completed the studies and sent reports to Congress. Because promulgation of rules by the EPA has not been completed, it is not possible to assess at this time whether, or to what extent, this legislation will ultimately impact the Company. Water Quality: The Federal Water Pollution Control Act Amendments of 1972, and amendments thereto, provide for, among other things, the imposition of effluent limitations to regulate discharges of pollutants, including thermal discharges, into the waters of the United States, and the EPA has established effluent guidelines for the steam electric power generating industry. Discharges must also comply with state water quality standards. The Company has all federal and state water permits presently necessary for the operation of the Big Stone Plant. Water discharge permits for the Hoot Lake Plant and Coyote Station were renewed in 1997 and 1998, respectively, each for a five-year term. The Company 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 of the five dams is 3,450 kw (net unit capability of 3,441 kw at December 31, 1999). Solid Waste: Permits for disposal of ash and other solid wastes have been issued for the Big Stone Plant and Coyote Station. A renewal permit is pending for the Hoot Lake Plant, and the Company anticipates that it will obtain this renewal in due course. The Company estimates that the current ash disposal site at the Hoot Lake Plant will be filled to capacity within two to three years. The Company is evaluating its options, including increased marketing of the ash for construction purposes and building a new ash disposal site adjacent to the current site within the same permitted area. Although an estimate of the engineering costs required to construct a new facility has not been completed, the Company believes that the investment required will not have a significant impact on future plant operating costs. The EPA has promulgated various solid and hazardous waste regulations and guidelines pursuant to, among other laws, the Resource Conservation and Recovery Act of 1976, the Solid Waste Disposal Act Amendments of 1980, and the Hazardous and Solid Waste Amendments of 1984, which provide for, among other things, the comprehensive control of various solid and hazardous wastes from generation to final disposal. The states of Minnesota, North Dakota and South Dakota have also adopted rules and regulations pertaining to solid and hazardous waste. The total impact on the Company of the various solid and hazardous waste statutes and regulations enacted by the federal government or the states of Minnesota, North Dakota and South Dakota is not certain at this time. To date, the Company has incurred no significant costs as a result of these laws. In 1980, the United States enacted the Comprehensive Environmental Response, Compensation and Liability Act, commonly known as the Federal Superfund law, which was reauthorized and amended in 1986. In 1983, Minnesota adopted the Minnesota Environmental Response and Liability Act, commonly known as the Minnesota Superfund law. In 1988, South Dakota enacted the Regulated Substance Discharges Act, commonly known as the South Dakota Superfund law. In 1989, North Dakota enacted the Environmental Emergency Cost Recovery Act. Among other requirements the federal and state acts establish environmental response funds to pay for remedial actions associated with the release or threatened release of certain regulated substances into the environment. These federal and state Superfund laws also establish liability for cleanup costs and damage to the environment resulting from such release or threatened release of regulated substances. The Minnesota Superfund law also creates liability for personal injury and economic loss under certain circumstances. The Company 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 Federal Toxic Substances Control Act of 1976 regulates, among other things, polychlorinated byphenyls (PCBs). The EPA has enacted regulations concerning the use, storage and disposal of PCBs. The Company completed a program for the removal of PCB-filled transformers and capacitors by the end of 1987 and received Certificates of Disposal in 1989. The Company completed a removal program of PCB-contaminated mineral oil dielectric fluid from substation transformers and voltage regulators and continues to remove such oil from other electrical equipment. Health Effects of Electric and Magnetic Fields (EMF): In 1996, the National Research Council of the National Academy of Sciences, after evaluating more than 500 studies on the effects of EMF, found insufficient evidence to consider electric and magnetic fields a threat to human health. Although research conducted to date has found no conclusive evidence that electric and magnetic fields affect health, a few studies have suggested a possible connection with cancer. The utility industry continues to fund studies. The ultimate impact, if any, of this issue on the Company and the utility industry is impossible to predict. Capital Expenditures - -------------------- The Company is continually expanding, replacing and improving its electric utility facilities. During 1999, the Company invested approximately $21,486,000 for additions to its electric utility properties. During the five years ended December 31, 1999, the Company had gross electric property additions, including construction work in progress, of approximately $129,530,000 and gross retirements of approximately $49,534,000. The Company estimates that during the five years 2000 through 2004 it will invest approximately $125 million for electric utility construction. The Company continuously reviews options for increasing its generating capacity, but at this time has no firm plans for additional base load generating plant construction. The majority of electric utility expenditures for the five-year period 2000 through 2004 will be for work related to the Company's transmission and distribution system. Franchises - ---------- At December 31, 1999, the Company had franchises 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 Company serves. MANUFACTURING OPERATIONS ------------------------ General - ------- Manufacturing Operations consists of businesses involved in the following manufacturing activities: production of PVC pipe, agricultural equipment, frame-straightening equipment and accessories for the auto body shop industry, contract machining, and metal parts stamping and fabrication. In January 2000, the Company through Varistar acquired the assets and operations of Vinyltech Corporation. The Company derived 20 percent of its consolidated operating revenues from this segment in 1999, 20 percent in 1998, and 21 percent in 1997. The following is a brief description of each of these businesses: Precision Machine, Inc., located in West Fargo, ND and Pelican Rapids, MN, provides machining, foundry, and metal work for farm implement and industrial equipment industries and produces parts to customers' specifications from prototype to final production. Dakota Machine, Inc., located in West Fargo, ND, manufactures sugar beet pilers, continuous-pan sugar refiners, diffusion towers, and nearly all other types of equipment used by sugar beet refineries. BTD Manufacturing, Inc. (BTD), located in Detroit Lakes, MN, is a metal stamping and tool and die manufacturer. BTD stamps, machines, and assembles metal parts according to manufacturers' specifications primarily for the recreation vehicle industry and industrial manufacturers. Northern Pipe Products, Inc., located in Fargo, ND, manufactures and sells polyvinyl-chloride (PVC) pipe for municipal, rural water, irrigation and other uses in a fifteen-state area. Chassis Liner Corporation, located in Alexandria and Lucan, MN, manufactures and sells vehicle frame-straightening equipment and accessories used by the auto body shop industry. Mid-States Testing Company, located in Moorhead, MN, sells and tests rubber protective equipment for the electrical utility industry and other electrical workers. Vinyltech Corporation, located in Phoenix, AZ, manufactures and sells PVC pipe in Arizona, California, Nevada, and other southwestern states. Each of the subsidiaries described above are owned by Varistar. Competition - ----------- The various markets in which the Company's manufacturing entities compete are characterized by intense competition. These markets have many established manufacturers with broader product lines, greater distribution capabilities, greater capital resources and larger marketing, research and development staffs and facilities than the Company's manufacturing entities. The Company believes the principal competitive factors in its manufacturing segment are product performance, quality, price, ease of use, technical innovation, cost effectiveness, customer service and breadth of product line. The Company's manufacturing entities intend to continue to compete on the basis of their high performance products, innovative technologies, cost effective manufacturing techniques, close customer relations and support and their strategy of increasing product offerings. Some of the products sold by the companies in the manufacturing segment are purchased by companies in the recreational vehicle market, sugar beet industry, auto body shop industry and PVC pipe market. The growth in these markets has provided strong growth for the Company's manufacturing segment. A downturn in these markets could have an adverse impact on the financial results of the Company's manufacturing segment. In addition, Northern Pipe Products and Vinyltech's gross margin percentages are related to PVC resin prices. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is difficult to predict gross margin percentages or assume that historical trends will continue. Capital Expenditures - -------------------- During 1999, capital expenditures of approximately $6.9 million were made in Manufacturing Operations. Total capital expenditures for Manufacturing Operations during the five-year period 2000-2004 are estimated to be approximately $26 million. HEALTH SERVICES OPERATIONS -------------------------- General - ------- Health Services Operations consists of businesses involved in the sale, service, rental, refurbishing, and operation of medical imaging equipment and the sale of related supplies and accessories to various medical institutions. The Company derived 15 percent of its consolidated operating revenues from this segment in 1999, 16 percent in 1998 and 17 percent in 1997. Subsidiaries comprising Health Services Operations include the following: Diagnostic Medical Systems, Inc. (DMS), located in Fargo, ND, sells, services, and refurbishes diagnostic medical imaging equipment and related supplies and accessories. DMS sells radiology equipment manufactured by several entities, including Philips Medical Systems (Philips) a large multi-national company based in the Netherlands. Philips manufacturers fluoroscopic, radiographic and mammography equipment, along with ultrasound, computerized tomography (CT) scanners, magnetic resonance imaging (MRI) scanners and cardiac cath labs. DMS is also a supplier of medical film and related accessories. DMS markets mainly to hospitals, clinics and mobile service companies in North Dakota, South Dakota, Minnesota, Montana and Wyoming. DMS Imaging, Inc., a subsidiary of DMS located in Bemidji MN, operates mobile and in-house diagnostic medical imaging equipment, including CT, MRI, nuclear medicine services and other similar radiology services to hospitals, clinics and other medical providers located in 23 states. Combined, the Health Services subsidiaries cover the three basics of the medical imaging industry: (1) ownership and operation of the imaging equipment for health care 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. Each of the subsidiaries described above are owned by Varistar. Competition - ----------- The market for selling, servicing and operating diagnostic imaging services and imaging systems is highly competitive. In addition to direct competition from other contract providers, the companies within the health services segment compete with free-standing imaging centers and health care providers that have their own diagnostic imaging systems and with equipment manufacturers that sell imaging equipment to health care providers for full- time installation. Some of their direct competitors, which provide contract MRI services, have access to greater financial resources than the health services companies. In addition, some of the health services companies' customers are capable of providing the same services to their patients directly, subject only to their decision to acquire a high-cost diagnostic imaging system, assume the financial and technology risk, and employ the necessary technologies. The companies within this segment compete against other contract providers on the basis of quality of services, quality and magnetic field strength of imaging systems, price, availability and reliability. Capital Expenditures - -------------------- During 1999 capital expenditures of approximately $1 million were made in Health Services. Total capital expenditures during the five-year period 2000-2004 are estimated to be $42 million. OTHER BUSINESS OPERATIONS ------------------------- General - ------- The Company's Other Business Operations consists of businesses that are diversified in such areas as electrical and telephone construction contracting, transportation, telecommunications, entertainment, energy services, and natural gas marketing. During August 1999, the assets of the Quadrant municipal waste burning facility were donated to the City of Perham, Minnesota. On September 1, 1999, the Company acquired through Varistar, the flatbed trucking operations of E. W. Wylie Corporation. The Company completed the sale of certain assets of the radio stations and video production company owned by KFGO, Inc. and the radio stations owned by Western Minnesota Broadcasting Company during October, 1999. The Company derived 15 percent of its consolidated operating revenues from these diversified businesses in 1999, 11 percent in 1998, and 11 percent in 1997. The following is a brief description of each of these businesses: Moorhead Electric, Inc., located in Moorhead, MN, installs data cable for commercial and industrial computer networks, underground fiber-optic and copper cable for the telecommunications industry, and electrical wiring in residential, commercial, and industrial settings. Aerial Contractors, Inc., located in West Fargo, ND, builds and repairs overhead and underground electric distribution and transmission lines and substations, and installs underground fiber-optic, copper and coaxial cable for the telecommunications industry. Midwest Information Systems, Inc., headquartered in Parkers Prairie, MN, operates telephone and cable television businesses that together operate approximately 7,000 access lines. E. W. Wylie Corporation, located in Fargo, ND, is a contract and common carrier that operates a fleet of tractors and trailers in 48 states and 6 Canadian provinces. Otter Tail Energy Services Company (OTESCO), headquartered in Fergus Falls, MN was established in 1997 to pursue opportunities in the natural gas and electricity markets. It offers technical services, engineering services, performance-based service contracting and financial services related to these products. OTESCO has one subsidiary, Otter Tail Energy Management Company (OTEMCO), which was formed as a result of the acquisition of PAM Natural Gas, Inc. OTEMCO is a marketer of natural gas to commercial and institutional customers in Iowa, South Dakota, North Dakota and Minnesota. With the exception of OTESCO, Varistar owns each of the subsidiaries described above. OTESCO is a wholly owned subsidiary of Minnesota-Dakota Generating Company, which in turn is a wholly owned subsidiary of the Company. General Regulation - ------------------ The Company's operating telephone subsidiaries are subject to the regulatory authority of the MPUC regarding rates and charges for telephone services, as well as other matters. The operating telephone subsidiaries must keep on file with the MPUC schedules of such rates and charges, and any requests for changes in such rates and charges must be filed for approval by the MPUC. The telephone industry is also subject generally to rules and regulations promulgated by the FCC. The Company's operating cable television subsidiary is regulated by federal and local authorities. Competition - ----------- Each of the businesses in Other Business Operations is subject to competition, as well as the effects of general economic conditions, in their respective industries. Capital Expenditures - -------------------- During 1999, capital expenditures of approximately $4.7 million were made in Other Business Operations. Capital expenditures during the five-year period 2000-2004 are estimated to be approximately $17 million for Other Business Operations. FINANCING --------- The Company estimates that funds internally generated net of forecasted dividend payments, combined with funds on hand, will be sufficient to meet sinking fund payments on First Mortgage Bonds and preferred stock redemption requirements in the next five years and to provide for its estimated 2000-2004 consolidated capital expenditures. Additional short-term or long-term financing will be required in the period 2000 through 2004 for the maturity of long-term debt, in the event the Company decides to refund or retire early any of its presently outstanding debt or Cumulative Preferred Shares, or for other corporate purposes. The foregoing estimates of capital expenditures and funds internally generated may be subject to substantial changes due to unforeseen factors, such as changed economic conditions, interest rates, demand for energy, availability of energy within the power pool, cost of capacity charges relative to cost of new generation, competitive conditions, technological changes, acquisitions or divestitures of subsidiary companies, new environmental and other governmental regulations, tax law changes, and rate regulation. The Company's operating subsidiaries have been responsible for obtaining their own financing after the Company's initial equity investment and have developed financing arrangements with various banks. The Company has not typically made or guaranteed loans to its subsidiaries, or cosigned on any subsidiary's borrowing. The Company has access to short-term borrowing resources. As of December 31, 1999, the Company and its subsidiaries had unused credit lines totaling $32.7 million. EMPLOYEES --------- The Company and its subsidiaries had approximately 1,973 full-time employees at December 31, 1999. A total of 496 employees are represented by local unions of the International Brotherhood of Electrical Workers, of which 389 are employees of the Electric Operations segment and are covered by a three-year labor contract that was renewed in 1999 and expires November 1, 2002. The Company has never experienced any strike, work stoppage, or strike vote, and considers its present relations with employees as very good. Forward Looking Information - Safe Harbor Statement Under the Private --------------------------------------------------------------------- Securities Litigation Reform Act of 1995 ---------------------------------------- In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 (the Act), the Company has filed cautionary statements identifying important factors that could cause the Company's actual results to differ materially from those discussed in forward- looking statements made by or on behalf of the Company. When used in this Form 10-K and in future filings by the Company with the Securities and Exchange Commission, in the Company's press releases and in oral statements, words such as "may", "will", "expect", "anticipate", "continue", "estimate", "project", "believes" or similar expressions are intended to identify forward- looking statements within the meaning of the Act. Factors that might cause such differences include, but are not limited to, governmental and regulatory action, the competitive environment, economic factors, weather conditions, and other factors discussed under "Factors affecting future earnings" on pages 24 and 25 of the Company's 1999 Annual Report to Shareholders, filed as an Exhibit hereto. These factors are in addition to any other cautionary statements, written or oral, which may be made or referred to in connection with any such forward-looking statement or contained in any subsequent filings by the Company with the Securities and Exchange Commission. Item 2. PROPERTIES ---------- The Coyote Station, which commenced operation in 1981, is a 414,000 kw (nameplate rating) mine-mouth plant located in the lignite coal fields near Beulah, North Dakota and is jointly owned by the Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern Public Service Company. The Company has a 35 percent interest in the plant and was the project manager in charge of construction. On July 1, 1998, the Company became the operating agent of the Coyote Station. The Company, 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 Company, for the benefit of all three utilities, was in charge of construction and is now in charge of operations. The Company owns 53.9 percent 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 on-line from a standby mode. At December 31, 1999, the Company's transmission facilities, which are interconnected with lines of other public utilities, consisted of 48 miles of 345 kv lines; 363 miles of 230 kv lines; 684 miles of 115 kv lines; and 4,179 miles of lower voltage lines, principally 41.6 kv. The Company 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. Through Varistar, the Company owns facilities and equipment used to manufacture polyvinyl chloride pipe and perform metal stamping, fabricating, and contract machining; construction to equipment and tools, medical imaging equipment, a fleet of flatbed trucks, and the infrastructure to maintain approximately 7,000 access lines in its telecommunication companies. Management of the Company believes that the facilities and equipment described above are adequate for the Company's present businesses. All of the Company's electric utility properties, with minor exceptions, are subject to the lien of the Company's Indenture of Mortgage dated July 1, 1936, as amended and supplemented, securing its First Mortgage Bonds. 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, 1999. Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 2000) ---------------------------------------------------------- Set forth below is a summary of the principal occupations and business experience during the past five years of executive officers of the Company: DATES ELECTED ------------- NAME AND AGE TO OFFICE PRESENT POSITION AND BUSINESS EXPERIENCE - ------------ ------------- ---------------------------------------- John C. MacFarlane (60) 4/8/91 Present: Chairman, President and Chief Executive Officer John D. Erickson (41) 10/26/98 Present: Vice President, Finance and Chief Financial Officer Prior to 10/26/98 Director, Market Strategies & Regulation Marlowe E. Johnson (55) 4/12/93 Present: Vice President, Customer Service, North Dakota Douglas L. Kjellerup (58) 2/1/99 Present: Chief Operating Officer, Energy Delivery; Vice President, Marketing and Development Prior to 2/1/99 Vice President, Marketing and Development LeRoy S. Larson (54) 4/12/93 Present: Vice President, Customer Service, Minnesota and South Dakota Jay D. Myster (61) 10/1/98 Present: Corporate Secretary Prior to 10/1/98 Senior Vice President, Governmental and Legal, and Corporate Secretary Rodney C.H. Scheel (50) 4/10/95 Present: Vice President, Electrical Prior to 4/10/95 Director, Information Services Ward L. Uggerud (50) 2/1/99 Present: Chief Operating Officer, Energy Supply; Vice President, Operations Prior to 2/1/99 Vice President, Operations Jeffrey J. Legge (43) 4/10/95 Present: Controller Prior to 4/10/95 Manager, Tax Department The term of office of each of the officers is one year. Any officer elected may be removed by the vote of the Board of Directors at any time during the term. PART II Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER ----------------------------------------------------------------- MATTERS ------- The information required by this Item is incorporated by reference to the first sentence under "Otter Tail Power Company stock listing" on Page 50, to "Selected consolidated financial data" on Page 19 and to "Quarterly information" on Page 43 of the Company's 1999 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 19 of the Company's 1999 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 20 through 26 of the Company's 1999 Annual Report to Shareholders, filed as an Exhibit hereto. Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ---------------------------------------------------------- The Company does not have material market risk exposure related to foreign currency exchange rate risk, commodity price risk or interest rate risk. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ------------------------------------------- The information required by this Item is incorporated by reference to "Quarterly information" on Page 43 and the Company's audited financial statements on Pages 27 through 43 of the Company's 1999 Annual Report to Shareholders excluding "Report of Management" on Page 27, filed as an Exhibit hereto. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND --------------------------------------------------------------- FINANCIAL DISCLOSURE -------------------- None. PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT -------------------------------------------------- The information required by this Item regarding Directors is incorporated by reference to the information under "Nominees for Election as Directors" in the Company's definitive Proxy Statement dated March 10, 2000. 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 10, 2000. Item 11. EXECUTIVE COMPENSATION ---------------------- The information required by this Item is incorporated by reference to the information under "Summary Compensation Table," "Option/SAR Grants in Last Fiscal Year," "Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal Year-End Option/SAR Values," "Pension and Supplemental Retirement Plans," "Severance Agreements," and "Directors' Compensation" in the Company's definitive Proxy Statement dated March 10, 2000. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT -------------------------------------------------------------- The information required by this Item is incorporated by reference to the information under "Outstanding Voting Shares" and "Security Ownership of Management" in the Company's definitive Proxy Statement dated March 10, 2000. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ---------------------------------------------- None. PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K --------------------------------------------------------------- (a) List of documents filed: (1) and (2) See Table of Contents on Page 22 hereof. (3) See Exhibit Index on Pages 23 through 28 hereof. Pursuant to Item 601(b)(4)(iii) of Regulation S-K, copies of certain instruments defining the rights of holders of certain long-term debt of the Company are not filed, and in lieu thereof, the Company agrees to furnish copies thereof to the Securities and Exchange Commission upon request. (b) Reports on Form 8-K: None SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. OTTER TAIL POWER COMPANY By /s/ John D. Erickson ------------------------ John D. Erickson Vice President, Finance and Chief Financial Officer Dated: March 28, 2000 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: Signature and Title - ------------------- John C. MacFarlane ) Chairman, President and ) Chief Executive Officer ) (principal executive officer) ) and Director ) ) John D. Erickson ) Vice President, Finance and ) Chief Financial Officer ) (principal financial officer) ) ) Jeffrey J. Legge ) By /s/ John D. Erickson Controller ) ------------------------- (principal accounting officer) ) John D. Erickson ) Pro Se and Attorney-in-Fact ) Dated March 28, 2000 Thomas M. Brown, Director ) ) Dayle Dietz, Director ) ) Dennis R. Emmen, Director ) ) Maynard D. Helgaas, Director ) ) Arvid R. Liebe, Director ) ) Kenneth L. Nelson, Director ) ) Nathan I. Partain, Director ) ) Robert N. Spolum, Director ) OTTER TAIL POWER COMPANY TABLE OF CONTENTS ----------------- FINANCIAL STATEMENTS, SUPPLEMENTARY FINANCIAL DATA, SUPPLEMENTAL FINANCIAL SCHEDULES INCLUDED IN ANNUAL REPORT (FORM 10-K) FOR THE YEAR ENDED DECEMBER 31, 1999 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, 1999: Page in Annual Report to Shareholders ------------ Financial Statements: Independent Auditors' Report . . . . . . . . . . . . . . . . . . . . . 27 Consolidated Balance Sheets, December 31, 1999 and 1998. . . . . .28 & 29 Consolidated Statements of Income for the Three Years Ended December 31, 1999 . . . . . . . . . . . . . . . . . . . . . . . 30 Consolidated Statements of Changes in Common Shareholders' Equity for the Three Years Ended December 31, 1999. . . . . . . . . . . . . . . . . . 31 Consolidated Statements of Cash Flows for the Three Years Ended December 31, 1999 . . . . . . . . . . . . . . . . . . . . . . . 32 Consolidated Statements of Capitalization, December 31, 1999 and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Notes to Consolidated Financial Statements . . . . . . . . . . . . .34-43 Selected Consolidated Financial Data for the Five Years Ended December 31, 1999 . . . . . . . . . . . . . . . . . . . . . . . 19 Quarterly Data for the Two Years Ended December 31, 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Schedules are omitted because of the absence of the conditions under which they are required or because the information required is included in the financial statements or the notes thereto. EX-99 2 Exhibit Index to Annual Report on Form 10-K For Year Ended December 31, 1999 Previously Filed ---------------- As Exhibit File No. No. -------- ------- 3-A 10-Q for quarter 3 --Restated Articles of ended 6/30/99 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 2-14209 2-B-1 --Twenty-First Supplemental Indenture from the Company to First Trust Company of Saint Paul and Russel M. Collins, as Trustees, dated as of July 1, 1958. 4-D-2 2-14209 2-B-2 --Twenty-Second Supplemental Indenture dated as of July 15, 1958. 4-D-3 33-32499 4-D-7 --Thirty-Second Supplemental Indenture dated as of January 18, 1974. 4-D-4 33-46070 4-D-12 --Forty-Third Supplemental Indenture dated as of February 1, 1991. 4-D-5 33-46070 4-D-13 --Forty-Fourth Supplemental Indenture dated as of September 1, 1991. 4-D-6 8-K dated 4-D-15 --Forty-Fifth Supplemental 7/24/92 Indenture dated as of July 1, 1992. 4-D-7 8-A dated 1 --Rights Agreement, dated as of 1/28/97 January 28, 1997 (the Rights Agreement), between the Company and Norwest Bank Minnesota, National Association. 4-D-8 8-A/A dated 1 --Amendment No. 1, dated as of 9/29/98 August 24, 1998, to the Rights Agreement. 10-A 2-39794 4-C --Integrated Transmission Agreement dated August 25, 1967, between Cooperative Power Association and the Company. Previously Filed ---------------- As Exhibit File No. No. -------- ------- 10-A-1 10-K for year 10-A-1 --Amendment No. 1, dated as ended 12/31/92 of September 6, 1979, to Integrated Transmission Agreement, dated as of August 25, 1967, between Cooperative Power Associa- tion and the Company. 10-A-2 10-K for year 10-A-2 --Amendment No. 2, dated as of ended 12/31/92 November 19, 1986, to Integ- rated Transmission Agreement between Cooperative Power Association and the Company. 10-C-1 2-55813 5-E --Contract dated July 1, 1958, between Central Power Elec- tric 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 super- seded and are no longer in effect.) 10-C-3 2-55813 5-E-2 --Amendment No. 1 dated December 19, 1973, to Supplement Seven. 10-C-4 10-K for year 10-C-4 --Amendment No. 2 dated ended 12/31/91 June 17, 1986, to Supple- ment Seven. 10-C-5 10-K for year 10-C-5 --Amendment No. 3 dated ended 12/31/92 June 18, 1992, to Supple- ment Seven. 10-C-6 10-K for year 10-C-6 --Amendment No. 4 dated ended 12/31/93 January 18, 1994, to Supple- ment Seven. 10-D 2-55813 5-F --Contract dated April 12, 1973, between the Bureau of Reclamation and the Company. 10-E-1 2-55813 5-G --Contract dated January 8, 1973, between East River Electric Power Cooperative and the Company. 10-E-2 2-62815 5-E-1 --Supplement One dated February 20, 1978. 10-E-3 10-K for year 10-E-3 --Supplement Two dated ended 12/31/89 June 10, 1983. 10-E-4 10-K for year 10-E-4 --Supplement Three dated ended 12/31/90 June 6, 1985. Previously Filed ---------------- As Exhibit File No. No. -------- ------- 10-E-5 10-K for year 10-E-5 --Supplement No. Four, dated ended 12/31/92 as of September 10, 1986. 10-E-6 10-K for year 10-E-6 --Supplement No. Five, dated ended 12/31/92 as of January 7, 1993. 10-E-7 10-K for year 10-E-7 --Supplement No. Six, dated ended 12/31/93 as of December 2, 1993. 10-F 10-K for year 10-F --Agreement for Sharing ended 12/31/89 Ownership of Generating Plant by and between the Company, Montana-Dakota Utilities Co., and North- western Public Service Company (dated as of January 7, 1970). 10-F-1 10-K for year 10-F-1 --Letter of Intent for pur- ended 12/31/89 chase of share of Big Stone Plant from Northwestern Public Service Company (dated as of May 8, 1984). 10-F-2 10-K for year 10-F-2 --Supplemental Agreement No. 1 ended 12/31/91 to Agreement for Sharing Ownership of Big Stone Plant (dated as of July 1, 1983). 10-F-3 10-K for year 10-F-3 --Supplemental Agreement No. 2 ended 12/31/91 to Agreement for Sharing Ownership of Big Stone Plant (dated as of March 1, 1985). 10-F-4 10-K for year 10-F-4 --Supplemental Agreement No. 3 ended 12/31/91 to Agreement for Sharing Ownership of Big Stone Plant (dated as of March 31, 1986). 10-F-5 10-K for year 10-F-5 --Amendment I to Letter of ended 12/31/92 Intent dated May 8, 1984, for purchase of share of Big Stone Plant. 10-G --Big Stone Plant Coal Agreement by and between the Company, Northwestern Public Service, Montana-Dakota Utilities Co., and Kennecott Energy Company (dated as of December 16, 1999). ** 10-G-1 10-Q for quarter 10-B --Big Stone Coal Transportation ended 9/30/94 Agreement by and between the Company, Montana-Dakota Utilities, Northwestern Public Service Co., and Burlington Northern Railroad Company (dated as of July 18, 1994). Previously Filed ---------------- As Exhibit File No. No. -------- ------- 10-G-2 10-K for year 10-G-2 --Amendment No. 1, dated as of ended 12/31/95 December 27, 1995, to Big Stone Coal Transportation Agreement (dated as of July 18, 1994). 10-G-3 --Amendment No. 2, dated as of June 10, 1999, to Big Stone Stone Coal Transportation Agreement (dated as of July 18, 1994). ** 10-H 2-61043 5-H --Agreement for Sharing Owner- ship of Coyote Station Generating Unit No. 1 by and between the Company, Minnkota Power Cooperative, Inc., Montana-Dakota Utilities Co., Northwestern Public Service Company, and Minnesota Power & Light Company (dated as of July 1, 1977). 10-H-1 10-K for year 10-H-1 --Supplemental Agreement No. ended 12/31/89 One dated as of November 30, 1978, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1. 10-H-2 10-K for year 10-H-2 --Supplemental Agreement No. ended 12/31/89 Two dated as of March 1, 1981, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1 and Amendment No. 2 dated March 1, 1981, to Coyote Plant Coal Agreement. 10-H-3 10-K for year 10-H-3 --Amendment dated as of ended 12/31/89 July 29, 1983, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1. 10-H-4 10-K for year 10-H-4 --Agreement dated as of Sept. ended 12/31/92 5, 1985, containing Amendment No. 3 to Agreement for Sharing Ownership of Coyote Generating Unit No.1, dated as of July 1, 1977, and Amendment No. 5 to Coyote Plant Coal Agreement, dated as of January 1, 1978. 10-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). Previously Filed ---------------- As Exhibit File No. No. -------- ------- 10-I-1 10-K for year 10-I-1 --Addendum, dated as of March ended 12/31/92 10, 1980, to Coyote Plant Coal Agreement. 10-I-2 10-K for year 10-I-2 --Amendment (No. 3), dated as ended 12/31/92 of May 28, 1980, to Coyote Plant Coal Agreement. 10-I-3 10-K for year 10-I-3 --Fourth Amendment, dated as ended 12/31/92 of August 19, 1985, to Coyote Plant Coal Agreement. 10-I-4 10-Q for quarter 19-A --Sixth Amendment, dated as of ended 6/30/93 February 17, 1993, to Coyote Plant Coal Agreement. 10-K 10-K for year 10-K --Diversity Exchange Agreement ended 12/31/91 by and between the Company and Northern States Power Company, (dated as of May 21, 1985) and amendment thereto (dated as of August 12, 1985). 10-K-1 10-Q for quarter 10 --Power Sales Agreement ended 9/30/99 between the Company and Manitoba Hydro Electric Board (dated as of July 1, 1999). 10-L 10-K for year 10-L --Integrated Transmission ended 12/31/91 Agreement by and between the Company, Missouri Basin Municipal Power Agency and Western Minnesota Municipal Power Agency (dated as of March 31, 1986). 10-L-1 10-K for Year 10-L-1 --Amendment No. 1, dated as ended 12/31/88 of December 28, 1988, to Integrated Transmission Agreement (dated as of March 31, 1986). 10-M --Hoot Lake Coal Transportation Agreement by and between the Company and The Burlington Northern and Santa Fe Railway Company (dated as of July 19, 1999).** 10-N-1 10-K for year 10-N --Deferred Compensation Plan ended 12/31/91 for Directors, dated April 9, 1984.* 10-N-2 10-K for year 10-N-2 --Executive Survivor and Sup- ended 12/31/94 plemental Retirement Plan, as amended.* 10-N-3 --Form of Severance Agreement.* Previously Filed ---------------- As Exhibit File No. No. -------- ------- 10-N-4 10-K for year 10-N-5 --Nonqualified Profit Sharing ended 12/31/93 Plan.* 10-N-5 10-K for year 10-N-6 --Nonqualified Retirement ended 12/31/93 Savings Plan.* 10-N-6 10-K for year 10-N-6 --1999 Employee Stock ended 12/31/98 Purchase Plan. 10-N-7 10-K for year 10-N-7 --1999 Stock Incentive Plan.* ended 12/31/98 13-A --Portions of 1999 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. 27 --Financial Data Schedule. - -------- * Management contract or compensatory plan or arrangement required to be filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K. ** Confidential information has been omitted from such Exhibit and filed separately with the Commission pursuant to a confidential treatment request under Rule 24b-2. EX-10 3 EXHIBIT 10-G Confidential information has been omitted from this Exhibit and filed separately with the Commission pursuant to a confidential treatment request under Rule 24b-2. COAL SUPPLY AGREEMENT by and between OTTER TAIL POWER COMPANY, NORTHWESTERN PUBLIC SERVICE, MONTANA-DAKOTA UTILITIES CO. and KENNECOTT ENERGY COMPANY 2000 - 2001 December 16, 1999 TABLE OF CONTENTS Page No. -------- 1. TERM . . . . . . . . . . . . . . . . . . . . . 1 2. QUANTITY . . . . . . . . . . . . . . . . . . . 2 3. SOURCE . . . . . . . . . . . . . . . . . . . . 3 4. COAL QUALITY . . . . . . . . . . . . . . . . . 3 5. PRICING . . . . . . . . . . . . . . . . . . . 4 6. BILLING AND PAYMENT . . . . . . . . . . . . . 5 7. SAMPLING AND ANALYSIS . . . . . . . . . . . . 6 8. WEIGHING AND LOADING . . . . . . . . . . . . . 8 9. FORCE MAJEURE . . . . . . . . . . . . . . . . 9 10. TITLE . . . . . . . . . . . . . . . . . . . . 10 11. TERMINATION AND CANCELLATION . . . . . . . . . 10 12. INDEMNITY AND LIABILITY . . . . . . . . . . . 10 13. LAWS AND REGULATIONS . . . . . . . . . . . . . 10 14. NOTICES . . . . . . . . . . . . . . . . . . . 10 15. CONFIDENTIALITY . . . . . . . . . . . . . . . 11 16. WARRANTY AND LIABILITY . . . . . . . . . . . . 11 17. DISPUTE RESOLUTION . . . . . . . . . . . . . . 11 18. MISCELLANEOUS . . . . . . . . . . . . . . . . 13 COAL SUPPLY AGREEMENT by and between OTTER TAIL POWER COMPANY, NORTHWESTERN PUBLIC SERVICE, MONTANA-DAKOTA UTILITIES CO. and KENNECOTT ENERGY COMPANY THIS COAL SUPPLY AGREEMENT ("Agreement") is made and entered into as of December 16, 1999 (the "Effective Date"), by and between OTTER TAIL POWER COMPANY, NORTHWESTERN PUBLIC SERVICE, a Division of Northwestern Corporation, MONTANA-DAKOTA UTILITIES CO., a Division of MDU Resources Group, Inc., hereinafter together called "Buyers or Buyer" and CORDERO MINING COMPANY AND CABALLO ROJO INC., wholly owned subsidiaries of Kennecott Energy and Coal Company, and Kennecott Energy Company, an affiliate of Kennecott Energy and Coal Company, hereinafter together called "Seller." BACKGROUND: A. Seller desires to sell coal from its Cordero Rojo Complex, consisting of the Cordero and Caballo Rojo mines located in Campbell County, Wyoming ("the Mine"), under the terms and conditions herein set forth; and B. Buyers are public utilities engaged in the production of electricity and the furnishing of electric service to the public; C. Buyers, pursuant to the Agreement for Sharing Ownership of Generating Plant dated as of January 7, 1970, own and operate the Big Stone Power Plant located near Milbank, South Dakota (the "Plant"); D. To produce electricity at the Plant, Buyers need to secure an adequate supply of coal of the quality and quantity as set forth in this Agreement; and NOW, THEREFORE, for and in consideration of the mutual covenants and agreements of the parties contained herein, Seller agrees to sell and deliver to Buyers and Buyers agree to purchase, receive and pay for coal from Seller upon the following terms and conditions: 1. TERM ---- The Term of this Agreement shall be for * years commencing on January 1, 2000 and terminating on * unless sooner terminated as provided in Section 11 of this Agreement. 2. QUANTITY -------- (a) Minimum and Maximum Amounts --------------------------- Throughout the Term, Seller shall supply and sell and Buyer shall purchase a minimum of * tons and a maximum of * tons of coal each calendar year. Buyer shall provide Seller a written nomination of the annual tonnage amount within ten (10) days of the Effective Date for calendar year 2000 and *. Said nominated amounts shall be within the range of the above referenced minimum and maximum amounts and shall be the annual quantity ("Annual Quantity") of coal that Buyer is obligated to purchase and Seller is obligated to sell and supply for such calendar year. (b) Delivery Schedule ----------------- Deliveries shall be scheduled to occur in monthly quantities during each calendar year, with the first shipments of coal to be delivered to the Plant in sufficient quantities to allow the Plant to begin burning the coal on or before January 1, 2000. Within ten (10) days of the Effective Date, Buyer shall provide Seller with its written monthly schedule for calendar year 2000; *. In providing the monthly schedules to Seller, Buyer shall use its best faith efforts to provide an accurate estimate of its projected need for coal on a monthly basis. Buyer shall use best efforts to keep monthly quantities approximately equal except for scheduled overhaul and test burn periods. However, the parties agree that the monthly schedules are for the convenience of the parties and in no way binding on the Buyer and that no penalty of any kind shall accrue to Buyer if for any reason the Buyer is (1) unable to take delivery of the amount of monthly coal scheduled or (2) takes delivery of more coal than scheduled in order to make-up for any previous months' deficiencies. Except as provided in Section 2(c) below, any variance in the amount of monthly coal scheduled and actually delivered shall not relieve either Seller or Buyer from their respective obligations to sell and purchase the minimum amounts of coal set forth in Section 2(a). (c) Reduction in Quantities ----------------------- Where, through fault of the Buyer, Buyer fails to take delivery of the amount of coal scheduled for any month because an appropriate amount of suitable and compatible unit trains is not provided to Seller, the following shall apply: Seller shall have the option at its discretion to reduce, in the affected calendar year, the amount of coal that it is obligated to provide under Section 2(a) in the amount that Buyer fails to take delivery. Seller may reduce its supply obligation only by giving Buyer written notice of its intent to do so within 10 days of the end of the calendar quarter in which the failure to take delivery occurs. When Seller provides such notice to Buyer, such notice shall also relieve Buyer of any further obligation with regard to purchasing or taking delivery of the reduced amount. Seller's option to reduce its supply obligation as provided above does not apply when the failure to provide an appropriate amount of suitable and compatible unit trains is not through any fault of Buyer. Failure by the rail car carrier to provide an appropriate amount of suitable and compatible unit trains to Seller shall not be considered the fault of the Buyer. Buyer agrees, however, to use its best efforts to assure that the appropriate amount of suitable and compatible unit trains is provided to the Seller by the rail car carrier, in order to take the amount of coal scheduled for delivery during each calendar month. (d) Additional or Lesser Quantities ------------------------------- Buyer and Seller may agree to increase or decrease the Annual Quantity as nominated by Buyer in Section 2(a) throughout the Term by designating any such increase or decrease in a written instrument signed by duly authorized representatives of the parties. (e) Additional Cost to Buyer through Fault of Seller ------------------------------------------------ Where Seller fails, through no fault of the Buyer or rail car carrier, to load Buyer's rail cars with coal on a timely basis that causes coal to be delivered to Buyer on an untimely basis or not at all, and where, as a result, Buyer incurs additional costs in a commercially prudent and verifiable manner, either because Buyer must use coal that it did not plan to use from its outside, inactive storage stockpile or secure coal from other sources, Seller shall be responsible to Buyer for these prudent and verifiable additional costs. Seller shall have the right of first refusal to provide the coal to replenish Buyer's outside inactive storage stockpile. Any additional coal provided by Seller under this section will increase the nominated amount of coal (pursuant to Section 2(a)) on a ton-per-ton basis. 3. SOURCE ------ The source of coal to be sold pursuant to this Agreement shall be mined and supplied from the Mine. Seller represents and warrants that the Mine contains coal of a quality and in quantities which will be sufficient to satisfy the requirements of this Agreement. Seller further warrants that the title to all coal delivered under this Agreement shall be good and that such coal shall be delivered free from any claim, lien or other encumbrance. 4. COAL QUALITY ------------ Coal supplied hereunder will be substantially free from impurities and foreign matter such as, but not limited to, dirt, bone, slate, earth, rock, pyrite, wood, tramp metal and mine debris prior to leaving the Mine. Coal will be raw, run-of-mine, crushed to 2" x 0" (ASTM). Seller represents that typical values of BTUs, moisture, ash, sulfur, and the values for other quality characteristics are as set forth in Exhibit A to this Agreement. Seller shall make its best commercial efforts to provide Buyer by facsimile transmission an analysis of the trainload of coal within twenty-four hours of loading the coal on the train for shipment to the Plant, Sunday through Thursday, and within forty-eight hours Friday and Saturday. Where the analysis shows that the coal fails to meet the minimum of the specification set forth in Exhibit A for BTUs by * or maximums of the specifications set forth in Exhibit A by the following amounts - * Ash; * Sulfur; or * Moisture - - Buyer shall have the right but not the obligation to reject the coal within twenty-four (24) hours of receiving the analysis from Seller.1 In the event Buyer rejects such non-conforming coal, title to and risk of loss of the coal shall be considered to have never passed to Buyer and Buyer may, at its sole option, stop the shipment of the non-conforming coal in route, prevent the unloading of the non-conforming coal, return the coal to Seller, or agree with Seller on a different disposition for such coal, all at Seller's cost and risk. Within twenty (20) working days from notice of rejection Seller shall replace the non-conforming coal with coal conforming to the specifications set forth above. 5. PRICING ------- The price of coal supplied hereunder shall be based on the following schedule. Prices will be per ton F.O.B. Buyer's railcars at the Mine (the "Base Price"). The Base Price for each year includes all Governmental Impositions as of December 16, 1999. BASE PRICE YEAR PER TON - ---- ------- * * * * (a) Base Price ---------- The Base Price may be adjusted only in accordance with Paragraph b and c of this Section 5. (b) Governmental Impositions and Taxes ---------------------------------- Seller represents that the Mine is in compliance with all governmental laws, rules and regulations in effect as of December 16, 1999, and that the cost of such compliance, including Mine closure and all reclamation costs, is included in the Base Price set forth in Section 5(a). If the imposition or repeal of any law, regulation or ruling (including changes in interpretations or administration of existing laws, regulations or rulings), or change in tax rate, is adopted or becomes effective on or after December 16, 1999 (hereinafter called "Governmental Imposition") and the imposition, repeal, or change in tax rate was not known as of the Effective Date, Seller shall demonstrate to Buyer, to Buyer's satisfaction, that such Governmental Imposition has ____________ 1 For example, Buyer shall have the right but not the obligation to reject the coal where the analysis shows that the BTUs are less than * or has an Ash content of more than *. increased or decreased the cost of owning or operating the Mine as it relates to the production of coal from the Mine for sale to Buyer under this Agreement. Upon agreement of the parties, the then effective Base Price shall be adjusted by adding or subtracting the per ton cost of the Governmental Imposition to determine an adjusted Base Price. If the Governmental Imposition will continue for the life of this Agreement, then the Base Price, to be included in an extension of the term of this Agreement, if any, shall also be adjusted by the per ton amount of the Governmental Imposition. Seller shall submit to Buyer in writing, an analysis identifying the Governmental Imposition causing the cost impact and the extent of such cost impact on ownership or operation of the Mine or on the production of coal purchased hereunder and showing the calculation of the amount of change in the Base Price. The effective date of any price increase or decrease pursuant to this Section 5(b) shall be the effective date of the Governmental Imposition causing the cost increase or decrease but, in no event prior to the date of actual expenditure or accrual thereof by Seller. (c) Adjustment for Calorific Value ------------------------------ The Base Price is calculated on the assumption of an average monthly calorific coal value of * per pound (the "Specified Average"); provided, however, the parties recognize that the calorific value of coal actually delivered hereunder may vary from such Specified Average. If the weighted average calorific value of the coal furnished in any month deviates from the Specified Average, then an adjustment will be made to the Base Price of coal according to the following equation: A = (B/C) X (D) Where: A - Adjusted Price rounded to the nearest mil ($.001) B - Weighted average (BTUs per pound) calorific value of coal delivered during the month. C - Specified Average (BTUs per pound) calorific value of coal which is * per pound. D - Base Price 6. BILLING AND PAYMENT ------------------- On or before the fifth (5th) and twentieth (20th) working day of each month, Seller shall render to Buyer at its Plant address provided in Section 14 a semi-monthly invoice which shall indicate the actual tonnage and weighted average calorific value of coal shipped during the previous billing period and the Adjusted Price which takes calorific value into account as defined in Section 5(c) and changes resulting from the changes in Governmental Impositions, if any. Buyer shall electronically pay such invoice within ten (10) working days after receipt thereof. Unless advised in writing to send all payments to another address, payment shall be sent by electronic means to: First Security Bank of Utah ABA No. 124000012 Account Number: 060-00064-56 Account Name: Cordero Mining Company/Caballo Rojo Inc. Receipts If Buyer defaults on any payment, Buyer shall pay simple interest thereon at the rate, not to exceed applicable State of Wyoming and Federal laws, that shall be equal to two percent (2%) over the base rate of interest charged by Citibank of New York or any successor bank on new ninety-day loans to responsible and substantial commercial borrowers on the date the interest charge begins. Such interest shall run from the date the payment was due until it is paid. If any invoice is in dispute, Buyer nevertheless shall pay the undisputed amount, and if Buyer or Seller is due any credit or payment pursuant to the resolution of the dispute, the simple interest on the credit or payment shall be paid by the party owing such credit or payment at the rate, not to exceed applicable State of Wyoming and Federal laws, that shall be equal to two percent (2%) over the base rate of interest charged by Citibank of New York or any successor bank on new ninety-day loans to responsible and substantial commercial borrowers on the date of Buyer's payment or credit from Seller of the disputed invoice and shall run until the date payment or credit is made following resolution of the dispute. Should Buyer fail to pay Seller for any amount due and owing in accordance with this Section 6 within thirty (30) days after its receipt of Seller's written demand for payment, then Seller shall also have the right, but not the obligation, to suspend deliveries under this Agreement by so notifying Buyer in writing. Should Buyer fail to pay Seller for any amount due and owing in accordance with this Section 6 within ninety (90) days after its receipt of Seller's written demand for payment, then Seller shall have the right, but not the obligation to terminate this Agreement by so notifying Buyer in writing. Such suspension or termination shall become effective as of the date that said written notice is received by Buyer. Neither Party shall accrue any additional rights against the other as a result of a suspension or termination permitted in this Section 6. Seller shall lose the right provided in this Section 6 to suspend or terminate if it has not sent written notice of such suspension or termination prior to Buyer's payment of the amount due and owing. Seller's failure to exercise its right to suspend or terminate as provided in this Section 6 shall not be deemed a waiver of its right to suspend or terminate for any subsequent default by Buyer to perform as provided in this Section 6. 7. SAMPLING AND ANALYSIS --------------------- (a) Seller shall cause, at its expense, each shipment of coal to be sampled and analyzed at the applicable mine in accordance with applicable ASTM standards. Buyer shall have the right, at its risk and expense, to have a representative present at any and all times to observe sampling and analysis procedures. All samples shall be divided into three (3) parts and put in suitable airtight containers. One part shall be furnished to Buyer for its analysis, one part shall be retained for analysis by Seller or its designee (which analysis shall be the basis for payment), and the third part shall be retained by Seller or its designee in one of the aforesaid containers properly sealed and labeled for a period forty-five (45) days after the date of sample collection. Buyer's samples are to be clearly labeled as to mine, date of sampling, date of preparation, and other identification as to shipment (such as train identification number) and are to be sent within forty-eight (48) hours of train loading, or prior to arrival of train at destination, whichever comes first, to Buyer at the address provided in Section 14. (b) Seller shall perform at Seller's cost a "short proximate" analysis (for moisture, ash, sulfur, sodium, and calorific value) for each trainload sample and will forward such analysis to Buyer by a mutually agreed upon method of electronic communication. (c) If a dispute arises between Buyer and Seller concerning a trainload sample due to a difference between Buyer's and Seller's analyses within forty-five (45) days of the date on which the subject trainload was loaded, an analysis of the third part shall be made by an independent commercial testing laboratory, mutually chosen by Buyer and Seller. The average of the results of the two (2) closest analyses with respect to the disputed quality characteristic (among Seller's, Buyer's and the independent laboratory's analyses) shall be controlling for purposes of the trainload in question. The cost of analysis made by such independent commercial laboratory shall be borne by the party whose analysis is not used in the final determination; provided, however, in the event the commercial laboratory's results are inconclusive and therefore not used, the cost of the analysis shall be shared equally by the parties hereto. (d) Seller shall provide Buyer the results of the proximate analysis for each trainload of coal as soon as the results are available, but in any event prior to the arrival of the subject train at the Plant. Upon Buyer's written request and at Buyer's cost, Seller shall analyze shipments designated by Buyer for mercury and chlorine content and submit such analysis to Buyer. (e) The results of the sampling and analysis performed by Seller shall govern for purposes of determining any adjustments to the Base Price of coal set forth in Section 5(c) for variations in calorific value, except in the event a dispute arises under Section 7(c), in which event Section 7(c) shall control. 8. WEIGHING AND LOADING -------------------- (a) Point of Delivery ----------------- Coal will be delivered F.O.B. Buyer's railcars at Seller's railroad loadout facility at the Mine. Upon completion of the loading of each railcar, title and risk of loss for all coal loaded therein will pass to Buyer. Buyer will arrange for the provision of suitable and compatible unit trains of open-top railcars for the transportation of coal purchased by Buyer under this Agreement. (b) Loading Facilities and Procedure -------------------------------- Seller will operate its loading facilities twenty-four (24) hours per day, 365 days per year. Seller will load each unit train at Seller's expense as closely as practicable to its full visible capacity. Seller will complete the loading of each unit train within four (4) hours after the first empty railcar is placed into position for loading. Unless excused by Force Majeure as provided below, Seller will pay Buyer for any increased transportation charges incurred as a result of Seller's failure to comply with the freetime, overloading and underloading set forth in the excerpts from Buyer's transportation agreement provisions as set forth in Exhibit C. The parties agree that "Actual Placement," as set forth in Exhibit C (section 10(B)(2)), means when the first empty railcar is placed under the spout and ready for loading. (c) Weighing -------- The weight of coal sold and delivered under this Agreement shall be determined on a per shipment basis by certified commercial scales at Seller's train loading facility at the Mine. The weights thus determined shall be accepted as the quantity of coal for which invoices are to be rendered and payments made in accordance with Section 6. Seller shall furnish the railroad company transporting the coal with copies of the weights determined under this Agreement. Coal supplied under this Agreement will be weighed at Seller's expense. Seller's scales used to determine such weight shall be tested, calibrated and certified in accordance with intervals of approximately every six (6) months by a qualified testing agency. Seller shall use its best efforts to give Buyer no less than ten (10) days notice of the anticipated time of scale test. Buyer shall also have the right, at Buyer's expense and upon reasonable notice, to have the scales checked for accuracy at any reasonable time or frequency. If the scales are found to be over or under the tolerance range allowable for the scale based on ASTM standards, either party shall pay to the other any amounts owed due to such inaccuracy for a period not to exceed thirty (30) days before the time any inaccuracy of scales is determined. Buyer shall have the right, at its own cost and expense, to have a representative present at any and all times to observe the weighings or scale test, and in a manner that does not interfere with Seller's operation of its Mines. (d) Data Transmission ----------------- Seller shall provide to Buyer within 48 hours of completion of loading each train a train loading manifest for each train by a mutually agreed upon method of electronic transmission. 9. FORCE MAJEURE ------------- (a) Definition ---------- For purposes of this Agreement, the term "Force Majeure" is defined as any cause or causes beyond the reasonable control and without the intentional fault or willful negligence of the party affected thereby which is the proximate cause of a party's whole or partial inability to perform its obligations under this Agreement. For purposes of this Agreement, Force Majeure includes, without limitation, Acts of God, unusual accumulations of snow or ice, floods, frozen coal, interruptions of transportation, interruptions or breakdowns of the power facilities connecting with Buyer or Seller's facilities, embargoes, acts of civil authority (including State and Federal agencies and courts of competent jurisdiction), acts of military authority, war, insurrections, riots, strikes, lockouts, work stoppages, labor or material shortages, or explosions, fires or unanticipated or non- routine mechanical breakdowns (including shutdowns for emergency maintenance or the like which may be necessary to mitigate or eliminate the imminent threat of explosions, fires, or mechanical breakdowns) at the Mine or at Buyer's Plant . Force Majeure also includes other causes of a similar nature which wholly or partially prevent the mining, hauling, processing, or loading of coal by Seller or the receiving, transporting, storing, unloading or utilizing of coal by Buyer. (b) Effect of Force Majeure ----------------------- If, because of an event of Force Majeure, either Seller or Buyer is unable to carry out any of its obligations under this Agreement, except obligations to pay money to the other party due to coal already sold, and if such party shall promptly give to the other party written notice of such event of Force Majeure, then the obligations under this Agreement of the party giving such notice shall be suspended to the extent made necessary by such event of Force Majeure and will continue throughout the continuance of such event; provided, however, that the party giving such notice shall use good faith efforts to eliminate such event of Force Majeure or its effect insofar as possible with a minimum of delay. Nothing herein contained shall cause the party invoking Force Majeure to submit to what it considers to be unreasonable conditions or restrictions, to make an unreasonable expenditure of money or to submit to a labor Agreement it deems unfavorable, and it is agreed that any settlement of labor strikes or difference with workmen shall be entirely within the sole discretion of the affected party. Deficiencies in receiving coal caused by a Force Majeure event shall be made up only upon mutual consent between Buyer and Seller. 10. TITLE ----- Title, right of possession and risks of loss of the coal shall pass From Seller to Buyer upon loading into the railcar. Seller agrees to load in equipment supplied by Buyer or Buyer's agent in accordance with industry standards or rail carrier's instructions. 11. TERMINATION AND CANCELLATION ---------------------------- Either party to this Agreement may cancel this Agreement upon written notice to the other party of such party's failure to comply with any of the material provisions or obligations in this Agreement, provided that notice of such failure has been given and not less than thirty (30) days have elapsed with no curative action having commenced. Seller and Buyer may terminate this Agreement immediately upon written notice to the other in the event the other becomes insolvent or files for protection under any applicable bankruptcy laws. Buyer shall remain obligated to pay for all coal delivered by Seller and accepted by Buyer prior to the date of termination or cancellation. 12. INDEMNITY AND LIABILITY ----------------------- Each party hereby agrees to indemnify, save and hold harmless the other, from and against all liability from damage to property or injury or death of any person or persons arising out of or resulting from the willful or negligent acts or omissions of such party, its agents and employees; provided however, that when employees or agents of either party hereto enter upon the premises of the other party, such entry shall be at the sole risk of the party who is the employer of such employee or agent, and such employer shall hold harmless the other party from all claims by its employees or agent, unless such injury or death or damage to property is a result of gross negligence. 13. LAWS AND REGULATIONS -------------------- The Seller and Buyer shall comply with all applicable federal, state and local laws, ordinances, statutes, codes, rules, and regulations in the performance of its obligations under this Agreement. 14. NOTICES ------- All notices required hereunder will be in writing and will be deemed properly given when sent by telecopy, to the addresses as provided below, or to such other addresses as Buyer or Seller may hereafter specify for such purpose, provided that all notices will be confirmed immediately by commercial delivery service, e.g., Federal Express or U.P.S. or registered certified mail. Buyer's address is: Seller's address is; - ------------------- -------------------- Big Stone Plant Kennecott Energy Company c/o Otter Tail Power Company 505 S. Gillette Avenue P.O. Box 218 Caller box 3009 Big Stone City, SD 57216 Gillette, Wyoming 82717 Attn: Fuel Supervisor Attn: Contract Administration Fax (605) 862-6344 Fax (307) 687-6009 With a courtesy notice to: With a courtesy notice to: - -------------------------- -------------------------- Attn: Production Services John Turyn, Manager Sales Otter Tail Power Company Kennecott Energy Company 215 South Cascade Street Suite 433, 6300 South Syracuse Fergus Falls, MN 56537 Englewood, CO 80111 Fax: (218) 739-8629 15. CONFIDENTIALITY --------------- Except as hereinafter provided, the terms and conditions set forth in this Agreement, and all information supplied to the other party pursuant to this Agreement, are considered by both Buyer and Seller to be confidential, and neither party shall disclose any such information to any third party without the advance written consent of the other party, which consent shall not be unreasonably withheld, except where such disclosure may be required by law or in connection with the assertion of a claim or defense in judicial or administrative proceedings involving the parties hereto, in which event the party required to make such disclosure shall advise the other in advance in writing and shall cooperate to the extent practicable to minimize the disclosure of any such information. 16. WARRANTY AND LIABILITY ---------------------- OTHER THAN THE WARRANTIES EXPRESSLY SET FORTH IN THIS AGREEMENT, SELLER MAKES NO OTHER EXPRESS OR IMPLIED WARRANTIES, INCLUDING WITHOUT LIMITATION, WARRANTIES OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR ARISING FROM A COURSE OF DEALING OR TRADE USAGE AND SELLER SHALL NOT BE LIABLE, WHETHER AS TO COAL SHIPPED OR FOR THE FAILURE TO SHIP COAL HEREUNDER, FOR ANY EXEMPLARY, SPECIAL, INCIDENTAL OR CONSEQUENTIAL DAMAGES WHATSOEVER. 17. DISPUTE RESOLUTION ------------------ (a) No Party to this Agreement shall be entitled to take legal action with respect to any dispute arising from or relating to the Agreement until it has complied, in good faith, with the procedures set forth in sections (b) and (c) below. (b) Negotiation ----------- (1) The parties shall attempt promptly and in good faith to resolve any dispute arising out of or relating to this Agreement through negotiations between representatives who have the authority to settle the controversy. All negotiations pursuant to this clause shall be confidential and treated as compromise and settlement negotiations for the purpose of the federal and state rules of evidence. (2) Either party may give the other written notice of any dispute not resolved in the normal course of business. As soon as mutually agreeable after delivery of this notice, representatives of the parties shall meet at a mutually acceptable time and place (or by telephone), and thereafter as often as they reasonably may deem necessary to attempt to resolve the dispute. Unless the parties to the dispute agree that the dispute cannot be resolved through unassisted negotiation, negotiations shall not be deemed at an impasse until 60 days after the first settlement conference. (3) If a negotiator intends to be accompanied at a meeting by any attorney, the other negotiator(s) shall be given at least three working days' notice of such intention and may also be accompanied by an attorney. (c) Alternative dispute resolution procedure ---------------------------------------- (1) If a dispute has reached impasse, either party may suggest use of alternative dispute resolution ("ADR") procedures. Once that party has notified the other of desire to initiate ADR, the parties may select the ADR method they may wish to use by mutual agreement. That ADR method may include arbitration, mediation, mini-trial, or any other method that best suits the circumstances of the dispute. The parties shall agree in writing to an ADR method selected and to the procedural rules to be followed as promptly as possible. To the extent the parties are unable to agree on procedural rules in whole or in part, the current center for public resources ("CPR") model procedure for mediation of business disputes, CPR model mini-trial procedure, or CPR commercial arbitration rules-whichever applies to the chosen ADR method-shall control, to the extent such rules are consistent with the provisions of this section. (2) If the parties are unable to agree on an ADR method or unwilling to use ADR to resolve the dispute, either party shall be free to resort to litigation. (3) If the parties agree on an ADR method other than arbitration, the decision rendered in that proceeding shall not be binding on any party except by agreement of the parties, and either party may seek resolution of the dispute through litigation. If the parties agree on arbitration as an ADR method, the decision of the arbitrator(s) shall be binding on all parties, pursuant to the United States Arbitration Act 9 USCA Sec. 1 et seq. The arbitrator(s) shall not award punitive or exemplary damages against either party. 18. MISCELLANEOUS ------------- (a) Governing Law. This Agreement shall be subject to and governed by the laws of the State of Minnesota. (b) Binding Effect. This Agreement shall inure to the benefit of and be binding on the parties hereto, their successors and assigns. (c) Assignment. Neither party hereto may assign this Agreement or any rights or obligations hereunder, in whole or in part, without the prior written consent of the other party, which consent shall not be unreasonably withheld or denied. However, consent shall not be required for merger, consolidation or sale of all or substantially all of the assets of a party. (d) Severability. If any provision of this Agreement is found to be contrary to law or unenforceable by a court of competent jurisdiction, the remaining provisions shall be severable and enforceable in accordance with their terms, unless such unlawful or unenforceable provision is material to the transactions contemplated hereby, in which case the parties shall negotiate in good faith a substitute provision. (e) Amendments. Except as otherwise provided herein, this Agreement may not be amended, supplemented or otherwise modified except by written instrument signed by duly authorized representatives of the parties hereto. (f) Headings. The descriptive headings contained in this Agreement are for convenience only and do not constitute a part of this Agreement. (g) Entire Agreement. This Agreement contains the entire agreement and understanding between the parties hereto with respect to the subject matter hereof and there are no representations, understandings or agreements, oral or written, expressed or implied, that are not included herein. (h) Survival. At the time of termination of this Agreement or any cancellation hereof, the appropriate provisions hereof shall survive as necessary to complete any payment or credit provided for hereunder with respect to coal sold and delivered prior to the date of such termination or cancellation. (i) Agreement Drafted Jointly. The parties agree that both parties shared equally in the drafting of the Agreement and/or had full opportunity to provide suggestions and/or language that reflects the intent of the parties. OTTER TAIL POWER COMPANY NORTHWESTERN PUBLIC SERVICE, COMPANY a Division of Northwestern Corporation By: /s/ Ward Uggerud By: /s/ Glen R. Herr ------------------------------ ----------------------------------- Chief Operating Officer, Title: Energy Supply Title: Executive Vice President & COO --------------------------- ------------------------------ MONTANA-DAKOTA UTILITIES KENNECOTT ENERGY COMPANY, as CO., a Division of Agent for and on behalf of MDU Resources Group, Inc. Cordero Mining Company and Caballo Rojo Inc. By: /s/ Bruce Imsdahl By: /s/ Malcolm R. Thomas ------------------------------- --------------------------------- Bruce Imsdahl Title: Vice President Energy Supply Title: Vice President Market & Sales ----------------------------- ------------------------------ EXHIBIT A 1999-2001 CORDERO/ROJO COMPLEX FORECAST QUALITY 12/09/998 * EXHIBIT B (Estimated Governmental Impositions as of December 9, 1999) * Exhibit C - Attached Excerpt from Coal Transportation Agreement By and Between Otter Tail Power Company, Northwestern Public Service Company, Montana-Dakota Utilities Co., and Burlington Northern Railroad Company. SECTION 9. WEIGHING 9(A) Weighing. The parties agree that the weight of the Coal in the Coal Cars will be determined at Origins by the UTILITIES' Origin Mine operator. BN shall not be responsible for such weight determinations. The weights ascertained by said operators pursuant to Section 11(J) shall be used for the assessment of the freight charges thereunder. Weighing shall be performed on scales inspected semi-annually, at no cost to BN, in accordance with the then- current AAR Scale Handbook specifications for such scales, and subject to supervision and verification by BN or its agent. 9(B) Breakdown Of Scales. If weights cannot be determined due to a breakdown of the scales at Origins, the weight per Train to be used for the assessment of freight charges thereunder shall be determined by averaging the per car weights on the ten (10) immediately preceding weighed shipments from the same Origin to Destination, adjusted to any variance in the number of cars per shipment. 9(C) Gross Load Limit and Overloads. If a loaded Coal Car is found by BN to weigh in excess 270,000 pounds, BN shall, if necessary, switch said overloaded Coal Car and remove it from the Train. BN retains the right to refuse to accept or transport overloaded Car(s). BN is not be obligated to reduce the lading of such Car(s), which obligation is solely UTILITIES' under this Agreement. After UTILITIES, at no expense to BN, cause any excess Coal to be removed from the overloaded Coal Car, BN shall replace the Coal Car into the Train. For such services in removing and replacing each such Coal Car, UTILITIES shall pay a charge to BN of $372.00 per Coal Car. If the excess Coal is removed during the Free Time at Origin without removing the Coal Car from a Train, there shall be no charge to UTILITIES. BN reserves the right to increase the maximum gross weight on rail above 270,000 pounds. UTILITIES are not obligated to ship in excess of 270,000 pounds. SECTION 10. LOADING AND UNLOADING 10(A) Advance Notice and Loading. (1) BN will make Trains of empty Coal Cars available at Origins for loading. BN shall furnish the Origin Mine Operator not less than four (4) hours advance notice by radio, telex, telephone or other reasonable means of the arrival of such Trains of Coal Cars at Origin for loading. (2) UTILITIES and/or its Mine Operator shall be responsible for the loading of Coal Cars. The parties agree to cooperate with the Mine Operator to provide for the efficient loading of the Coal Cars at an Origin. BN shall provide Locomotives and Train crews to move Trains through the Loading Facility at a controlled speed as designated by UTILITIES Mine Operator; PROVIDED, HOWEVER, that BN will not be required to move Cars at a speed less than five tenths (.5) mile per CONFIDENTIAL CONTRACT ICC-BN-C-2913 10 hour, but to the extent it is able to operate at a lesser speed, will upon request use its best efforts to do so. 10(B) Placement and Free Time - Origin. (1) Four (4) hours free time will be allowed to load all empty Coal Cars in a Train, commencing after the Actual or Constructive Placement of the Train at the designated notification point at the Origin ready for loading "Loading Free Time"); PROVIDED, HOWEVER, that Loading Free Time shall be extended for a period of time equivalent to that by which loading was prevented as a result of (i) a Loading Disability, or (ii) any occurrence attributable to BN which prevents loading. If BN fails to provide four (4) hours advance notice of arrival at Origin, a Train's Loading Free Time shall be extended by the additional amount of time (but not to exceed four (4) hours) that it takes to load a Train due to BN's failure to provide the required notice. If a Train is not loaded and released during the applicable Loading Free Time, BN may collect from UTILITIES an Origin Detention Charge of $308.00 per hour (including any fraction of an hour) until such time as the Train is loaded and released. (2) For purposes of this Section 10. "Actual Placement" is made when a Unit Train arrives at Origin Mine's designated notification point (as described in the BN timetable and the Train crew has requested loading instructions. In the event a Train cannot be Actually Placed at an Origin, notice shall be given immediately to Origin Mine Operator by radio, telex, telephone or other reasonable means, and BN may place the Train at an available hold point until such time as Origin Mine Operator notifies BN that Actual Placement can be made, whereupon it shall be moved to Origin. (3) For purposes of this Section 10, "Constructive Placement" begins when a Train is placed at an available hold point because it is prevented from being Actually Placed; PROVIDED, HOWEVER, that Constructive Placement shall not take place when Actual Placement is prevented (i) due to any cause that would extend Loading Free Time, or (ii) because the Loading Free Time for another Train ahead of the Train in question has not expired ("Origin Bunching"). The time required for the movement of a Constructively Placed Train from a hold point to an Origin will not be included in the computation of Free Time. (4) "Loading Disability" means any of the following events which directly result in the inability to load Coal into a Train at an Origin: (i) an Act of God; (ii) a strike or other labor disturbance; (iii) a riot or other civil disturbance; (iv) rain, snow and/or ice accumulation sufficient to immobilize Train or Mine operations or prevent loading of such Train; (v) an act of regulation of local, state or federal government authorities; or (vi) mechanical or electrical breakdown, explosion or fire (including shutdown for emergency maintenance or the like which may be necessary to mitigate or eliminate the imminent threat of explosion, fire or mechanical or electrical breakdown), or accident affecting a Loading Facility at the Origin then being utilized by UTILITIES or affecting BN's locomotives or other railroad equipment. UTILITIES or UTILTIES' Mine Operator shall notify BN by telephone, telegraph, radio or other reasonable means (i) within one and one-half (1.5) hours of the commencement of a Loading Disability as to the nature and time of commencement of the Loading Disability, and (ii) within one and one-half (1.5) hours after the termination of a Loading Disability as to the time of termination of the Loading Disability, except that the notifications in (i) and (ii) above shall not be necessary if the Loading Disability lasts for a period of one and one-half (1.5) hours or less (*) Confidential information has been omitted and filed separately with the Commission pursuant to Rule 24b-2. EX-10 4 EXHIBIT 10-G-3 Confidential information has been omitted from this Exhibit and filed separately with the Commission pursuant to a confidential treatment request under Rule 24b-2. SECOND AMENDMENT TO TRANSPORATION AGREEMENT NUMBER ICC-BN-C-2913 This second Amendment to Coal Transportation Agreement numbered ICC-BN-C-2913 is made pursuant to 49 U.S.C. Section 10709, between THE BURLINGTON NORTHERN AND SANTA FE RAILWAY COMPANY (BNSF), as successor to Burlington Northern Railroad Company, and OTTER TAIL POWER COMPANY, NORTHWESTERN PUBLIC SERVICE COMPANY, and MONTANA-DAKOTA UTILITIES COMPANY, (hereinafter jointly referred to as "UTILITIES"). WHEREAS, BNSF and UTILITIES are parties to Transportation Agreement numbered ICC-BN-C-2913, dated July 18, 1994, and amended on December 27, 1995, governing transportation of Coal in unit trains from Montana and Wyoming Mine Origins to UTILITIES' Big Stone City steam electric power plant near Big Stone City, SD (hereinafter referred to as the "Original Agreement"); WHEREAS, the parties desire to amend the Original Agreement to increase its term. NOW, THEREFORE, in consideration of the premises, covenants and provisions set out herein, the parties hereto agree as follows: 1. EFFECTIVE DATE: This Second Amendment shall be effective on the date last signed below, and shall continue in force through *. 2. From sub-section "2(B). Term of Agreement" delete the sentence "This Agreement shall terminate at 11:59 p.m. Central Standard Time on December 31, 1999." and in its place substitute the following: This Agreement shall terminate at midnight on *. 3. From the second paragraph of "Section 2. Effective Date and Term" of the First Amendment of the Original Agreement delete the sentence "The term of this First Amendment shall end at 11:59 p.m. Central Standard Time on December 31, 1999." And in its place substitute the following: This First Amendment shall terminate at midnight on *. 4. At the end of Sub-Section "3(A) Covered Mines, Origins or Mine Origins" add the following Mine and BNSF Origin to Group D: MINE BNSF ORIGIN ---- ----------- * * 5. From the first sentence of first paragraph of Sub-Section "7(C) Minimum Tonnage Requirement or BTU Equivalent" delete the date "December 31, 1999" and in its place substitute *. 6. From the first paragraph of Sub-Section "7(C) Minimum Tonnage Requirement or BTU Equivalent" delete the term * and in its place substitute *. 7. From the first paragraph of Sub-Section "7(C ) Minimum Tonnage Requirement or BTU Equivalent" delete the example "EXAMPLE: Group B Origin * and in its place substitute the following: EXAMPLE: Group B Origin: * 8. Delete the last sentence of subsection "14(C) Effect on Minimum Tonnage Requirement or BTU Equivalent" and in its place substitute the following: Force Majeure days shall be carried over into succeeding years for purposes of calculating compliance with the Minimum Tonnage Requirement or BTU Equivalent thereunder. 9. As amended and supplemented by this Second Amendment, The Original Agreement shall remain in full force and effect. IN WITNESS WHEREOF, the parties hereto have caused the Second Amendment to Contract ICC-BN-C-2913 to be executed by their duly authorized representatives on the date last written below. OTTER TAIL NORTHWESTERN PUBLIC POWER COMPANY SERVICE COMPANY By: /s / Ward Uggerud By: /s/ Michael J. Hanson --------------------------------- ------------------------------ Title: Chief Operating Officer Title: President & CEO Energy Supply ----------------------------- ------------------------ Date: 6/4/99 Date: 6/1/99 ----------------------------- ------------------------ MONTANA-DAKOTA THE BURLINGTON NORTHERN AND UTILITIES COMPANY SANTA FE RAILWAY COMPANY By: /s/ Bruce Imsdahl By /s/ David S. Quilici --------------------------------- ---------------------------- Title: V. P. Energy Supply Title: VP Coal Marketing ----------------------------- ------------------------ Date: 6/2/99 Date: 6-10-99 ----------------------------- ------------------------ (*) Confidential information has been omitted and filed separately with the Commission pursuant to Rule 24b-2. EX-10 5 EXHIBIT 10-M Confidential information has been omitted from this Exhibit and filed separately with the Commission pursuant to a confidential treatment request under Rule 24b-2. THE BURLINGTON NORTHERN AND SANTA FE RAILWAY COMPANY TRANSPORTATION AGREEMENT BNSF-C-12221 This Agreement made pursuant to 49 U.S.C. Section 10709 between THE BURLINGTON NORTHERN AND SANTA FE RAILWAY COMPANY, (hereinafter referred to as "BNSF"), and OTTER TAIL POWER COMPANY (hereinafter referred to as "OTP"). WHEREAS, OTP owns and operates a stream electric generating plant described herein, known as the Hoot Lake Steam Plant (as defined hereinafter); and BNSF is a common carrier by rail with railroad track extending from coal mines in Wyoming and Montana to the vicinity of Hoot Lake Steam Plant; and WHEREAS, OTP desires BNSF to transport, and BNSF desires to transport for OTP, pursuant to the terms of this Agreement, certain tonnage of coal in Unit Trains to Hoot Lake Steam Plant; NOW, THEREFORE, in consideration of the premises and the agreements and conditions which hereinafter follow, the parties hereto agree as follows: SECTION 1. DEFINITIONS Actual Placement: When a Unit Train arrives at the Origin Mine's or Destination's designated notification point (as described in the BNSF timetable) and the Train crew has requested loading instructions or unloading car placement instructions. Adjusted Rate: The Base Rate specified in Section 4 herein, plus all increases and decreases made pursuant to Section 5 herein, applicable in determining the Effective Rate. Base Rate: The rate as set forth in Section 4 of this Agreement, expressed in United States dollars, cents per net Ton applicable to the transportation of Coal from Mine Origin(s) to Destination. Bunching Time, Train Bunching or Bunching: When a Unit Train arrives at or attempts to arrive at Origin or Destination and another Unit Train (or Unit Trains) occupies the Origin or Destination which prevents the Actual Placement for loading or unloading of the Unit Train for a period of one hour or more, not due to any cause attributable to BNSF (the "Bunched Unit Train"). Bunching shall be accounted for by BNSF's computer train records and BNSF's Coal Desk logs. Bunching time may or may not include time in which a train is under Constructive Placement. Coal: That mineral substance, untreated except for additives used to reduce freezing or dusting problems and currently designated as STCC Code 11212 by the Association of American Railroads. Coal Cars or Cars: Open-top, bottom dump, coal railroad cars having a net capacity of approximately 100 Tons per car, supplied by OTP, or temporarily substituted by BNSF, suitable for use in Unit Train service between Origin and Destination. Said Coal Cars must comply with the Field Manual of Interchange Rules and Office Manual of the Interchange Rules adopted by the Association of American Railroads ("AAR Interchange Rules") presently in effect and as they may be changed hereafter from time to time. Said Coal Cars must comply with any rules and regulations of the Federal Railroad Administration applicable to such Coal Cars. * Declared Annual Volume: The total annual tonnage volume, equal to or above the Minimum Annual Volume, declared by OTP by October 1 of the preceding calendar year that OTP intends to tender for transport under the terms specified herein in a given calendar year. CONFIDENTIAL CONTRACT BNSF-C-12221 Page l of 15 07/15/1999 at 1:56 PM Destination: Hoot Lake Steam Plant (hereafter referred to as "Hoot Lake") located near Fergus Falls, MN. Effective Rate: The annually Adjusted Rate specified in Section 4 and Section 5 herein, or the Base Rate, whichever is greater, and applicable to the transportation of Coal on the date the loaded Train is released to BNSF for transport to Destination pursuant to this Agreement. Free Time: The time allowed for a Unit Train to load or unload free of train detention charges. Free Time may be extended under conditions described in this Agreement. Loading Facility: All equipment necessary for loading of Trains at Origins including; rail track, raw Coal hopper, crusher, storage/load-out silos, and conveyor systems. Minimum Annual Volume: * Tons of coal in each calendar year during the term of this Agreement, subject to adjustment due to Force Majeure pursuant to the terms of this Agreement). Origin(s), Mine(s) or Mine Origin(s): The Coal Unit Train Loading Facilities located at the mines identified in Subsection 3(A) of this Agreement. Route of Movement: The BNSF rail route of loaded and empty Trains moving pursuant to this Agreement from or to any Wyoming or Montana Mine Origins specified in Subsection 3(A) through Huntley, MT, to or from Destination. STB: The Surface Transportation Board or its successor agency or body having the same or similar jurisdiction over rail common carriers operating in interstate commerce. Ton: A ton of 2,000 pounds avoirdupois. Tender: An offer by OTP or its mine operator to BNSF of Coal loaded in a Unit Train and ready for movement from one Origin to one Destination pursuant to the terms of this Agreement. Train or Unit Train or Train Set: A specialized train consisting of a specified number of Coal Cars furnished as a unit for shipment from one Origin to one Destination on one bill of lading at one time. Unloading Facility: All equipment necessary for unloading of Trains at Destination including: railroad track; dumper, including feeders and hopper; and dumper conveyors. SECTION 2. EFFECTIVE DATE AND TERM 2(A) Effective Date of Agreement. This Agreement is made pursuant to 49 U.S.C. Section l0709 and shall be effective on the date last signed below. 2(B) Date of Transportation under Agreement. The terms and conditions of this Agreement shall apply to all shipments of Coal made on or after July 15, 1999, in OTP furnished cars as described under the terms of this Agreement. 2(C) Term of Agreement. The term of this Agreement shall commence on the Effective Date in Subsection 2(A) above and shall expire at midnight MST on *. SECTION 3. MOVEMENTS COVERED BY THE AGREEMENT 3(A) Covered Mines, Origins or Mine Origins. BNSF will transport Coal to Destination from any of the Montana or Wyoming Mine Origins specified in Section 4(A) herein; provided that these Origins have adequate Loading Facilities and CONFIDENTIAL CONTRACT BNSF-C-12221 Page 2 of 15 07/15/1999 at 1:56 PM procedures as contemplated under this Agreement capable of consistently loading at least 113 Coal Cars in continuous motion in four (4) hours or less. 3(B) Exception to Route of Movement. BNSF may use any available alternate route when operating conditions exist which make use of the route identified herein inadvisable or impractical; provided, however, that when using alternate routes, BNSF shall use its best efforts to select the least circuitous routing and to otherwise minimize delays to OTP and shall not operate any Train on a route which goes outside the States of Wyoming, Montana, North Dakota, and South Dakota without OTP's prior consent; provided, however, that such consent shall not be unreasonably withheld. 3(C) Movement of Empty Trains and Change of Origin. BNSF will move empty Trains from Destination to one of the Origins as part of the service included under the rates provided in Section 4. OTP's notice of any change in Origin from the last loaded movement must be given to BNSF prior to departure of empty Trains from Hoot Lake. Notice may be given by telephone, or other means of direct communication with BNSF's Coal Operating Department. BNSF will use best efforts to accommodate OTP should it become necessary to change the Origin in the empty return Route of Movement. SECTION 4. TRANSPORTATION RATES 4(A) Base Rate. OTP shall pay to BNSF the following Base Rates (expressed in US dollars and cents per net ton) as of July 15, 1999, for the transportation of Coal from Origins to Destination under this Agreement, which rates shall be subject to adjustment beginning January 1, 2000 in accordance with Section 5: BASE RATES MONTANA MINE ORIGINS * NORTHERN MINE ORIGINS * CENTRAL MINE ORIGINS * SECTION 5. ADJUSTMENT OF RATES 5(A) Periodic Adjustments. Except as otherwise provided in this Agreement, the transportation rate set forth in this Agreement (that is, the Base Rate set forth in Section 4) shall be adjusted annually, upward or downward, by an amount equal to * of the change in the Rail Cost Adjustment Factor unadjusted for Railroad Productivity (RCAF-U) ("Adjustment Index") as defined in Ex Parte 290 Sub No. 4 (and further described in Subsection 5B) to produce the "Adjusted Rate." Adjustments shall become effective annually on January 1 of each calendar year, with the first adjustment to become effective on January 1, 2000. BNSF shall notify OTP in writing of all adjustments and furnish supporting calculations, prior to the effective date of the adjustment, or, as soon thereafter as the information necessary to calculate the adjustment is made by the STB. The new Adjusted Rate (and subsequent Effective Rate) so determined shall be effective retroactive to the applicable adjustment date in question. CONFIDENTIAL CONTRACT BNSF-C-12221 Page 3 of 15 07/15/1999 at 1:56 PM 5(B) Adjustment Percentage Change Application. Commencing on January 1, 2000, the Annual Percentage Change shall be equal to the *. The Annual Percentage Change (in decimal) will be multiplied by * to produce the Adjustment Percentage Change (in decimal). The previous annual Adjusted Rate is multiplied by the Adjustment Percentage Change to produce the "Change Amount." The previous Adjusted Rate plus the Change Amount will equal the new quarter's Adjusted Rate. The Effective Rate shall be equal to the Adjusted Rate if the Adjusted Rate is equal to or greater than the Base Rate else the Effective Rate shall be equal to the Base Rate. For example: * In no event shall the Effective Rate move below the Base Rate under this Agreement; if the Adjustment Index produces Adjusted Rates that are lower than the Base Rate, then the Effective Rate shall be equal to the Base Rate. In subsequent years, the Adjusted Rates that are below the Base Rate shall continue to be adjusted upward or downward, as applicable, and shall not be used to determine the Effective Rate until the level of the Adjustment Index produces Adjusted Rates that are above the Base Rate. 5(C) Rounding. All calculated numbers shall be rounded to the nearest sixth digit after the decimal point (i.e. .000001499 = .000001). All final adjustment computations shall be rounded to the nearest one cent by going to the lower cent when computations result in a balance of less than one-hag cent and to the next higher whole one cent when computations result in a balance of one-half cent or more (i.e. .044999 = $0.04 and .045000 = $0.05). 5(D) Elimination or Material Alteration of Index. If the STB or any successor organizations cease to publish the RCAF-U index required for the calculations outlined in this Section, or materially alters the methodology by which the index is derived, the parties shall mutually determine and agree upon the most appropriate substitute index which most closely matches the economic structure of the discontinued or altered index to be used for adjustments for the remainder of the Agreement term immediately following such action. If the parties do not come to an agreement as to the substitute index by an adjustment date, the Effective Rate shall not be adjusted until such time as the index is agreed to, at which time a retroactive adjustment shall be made retroactive to said adjustment date. If the parties do not reach agreement on the substitute index after 60 days following an adjustment date, eighty percent (80%) of the United States Gross Domestic Product - Implicit Price Deflator shall be the substitute index. The parties agree that the RCAF index adjusted for productivity (RCAF-A) (or other future RCAF indexes adjusted for productivity in some manner) will not be used under this Subsection 5(D) as a substitute index. SECTION 6. ENTIRE COMPENSATION The rates and charges specified in this Agreement shall constitute the entire compensation payable to BNSF for the rail transportation services specified in this Agreement. BNSF shall not seek to collect from OTP, CONFIDENTIAL CONTRACT BNSF-C-12221 Page 4 of 15 07/15/1999 at 1:56 PM except as provided herein, any additional amounts in connection with such specified services. The adjustment mechanism specified in Section 5 of this Agreement shall constitute the sole means of adjusting the rates specified in this Agreement during the term hereof. If OTP requests BNSF to perform additional services, not specified in this Agreement or incorporated herein by reference, charges for such services shall be established by separate agreement. SECTION 7. DESCRIPTION OF TRANSPORTATION AND TONNAGE REQUIREMENTS 7(A) Transportation Services and Obligations of the Parties. BNSF agrees to transport Coal subject to the terms of this Agreement. The transportation services to be provided by BNSF pursuant to this Agreement shall include all rail services and operations required for movements in Trains of loaded Coal Cars from Origin to Destination and the return movement in Trains of the empty Coal Cars to Origin, both via Route of Movement. These services are described as follows: (1) Transportation services including such switching and Car handling at Origin and Destination as may be required for loading and weighing at Origin and Unloading at Destination and, if requested by OTP, reversing the Train within the Free Time period at Destination. (2) Transportation services required for rail movements in Trains between Origin and Destination, including all marshaling of Cars, line-haul transportation, switching for Coal Car maintenance performed by BNSF, inspection of Coal Cars, storage of active spare Cars on the Route of Movement and other customary accessorial services required for efficient Train operations. BNSF shall provide the necessary locomotives, cabooses (if required), rear-end devices, materials, supplies and labor to enable it to transport the Coal tonnage to be Tendered to it pursuant to this Agreement. 7(B) Coal Cars. OTP hereby agrees to supply at least one hundred and thirteen (113) Coal Cars plus at least five spare Coal Cars suitable for interchange under Interchange Rules adopted by the Association of American Railroads for each Unit Train Tendered, for use by BNSF in accordance with the terms of this Agreement in order to allow BNSF to transport the Coal tonnage to be Tendered hereunder. Said Coal Cars shall be provided at no cost to BNSF. 7(C) Minimum Annual Volume. (1) Within each calendar year during the term of this Agreement after year 1999, OTP agrees to Tender, in reasonably equal monthly quantities, the Minimum Annual Volume of * Tons of Coal, as adjusted pursuant to this Agreement, under the conditions and in the manner specified herein, provided however, in calendar year 1999, the Minimum Annual Volume will be equal to * tons. OTP may Tender tonnage in excess of the Minimum Annual Volume. (2) Commencing in calendar year 2000, OTP shall provide to BNSF by October 1 of each preceding year during the term of this Agreement a written notice specifying the amount of Coal it intends to Tender under this Agreement during the calendar year ("Declared Annual Volume"). The Declared Annual Volume shall equal the Minimum Annual Volume plus any additional coal above the Minimal Annual Volume. The Declared Annual Volume shall indicate the amount of Coal OTP intends to ship during each quarter of the year. The Declared Annual Volume shall be for informational purposes only and is not binding. (3) If in any calendar year during the term of this Agreement, OTP does not Tender to BNSF the Minimum Annual Volume, OTP agrees to pay BNSF as liquidated damages, agreed as reasonable and not as a penalty, an amount equal to * of the applicable Effective Rate as of the end of such calendar year times the difference between the Minimum Annual Volume and the total tonnage Tendered by OTP to BNSF during such calendar year. CONFIDENTIAL CONTRACT BNSF-C-12221 Page 5 of 15 07/15/1999 at 1:56 PM The Minimum Annual Volume shall be adjusted by Force Majeure events as provided for in Section 14(C). OTP shall not reduce the Minimum Annual Volume by shipping any or all of the Minimum Annual Volume via another rail carrier and by paying liquidated damages to BNSF to satisfy the Minimum Annual Volume as adjusted pursuant to this Agreement, and in the event that OTP does so, said percentage of the applicable Effective Rate shall not be construed as an agreed upon measure of damages. (4) Any Tons which are not actually moved, but for which charges are paid pursuant to Subsection 11(J), will be considered as Tons received in meeting the Minimum Annual Volume. 7(D) BNSF Service Commitment. For the Minimum Annual Volume in Subsection 7(C) and Tendered for shipment from the Mine Origins, BNSF agrees to provide a minimum of * round trips per year (* trips in calendar year 1999), if OTP unloads in * hours and Origin Mines load the train in * hours. BNSF shall be granted relief from the * trips per year for the following reasons: (1). Train Bunching time and/or Constructive Placement time at the Mine Origin. (2). Train Bunching time and/or Constructive Placement time at Destination if there is a train not ready for release at the Destination preventing placement of the loaded train. (3). Any two week period where the Long Unload Cycle is used by OTP. (4). Delays caused by Force Majeure as defined in Section 14. (5). Any delay caused by OTP, OTP's loading or unloading operator. If the Deficit Tonnage is due to BNSF's failure to make the * round trips yearly, and as a result thereof, OTP does not ship the Minimum Annual Volume, BNSF shall take all reasonable steps, including the addition of locomotives, rail owned Coal Cars and crews to transport the Deficit Tonnage at a schedule consistent with the ability of the Origin Mine operator to load and OTP to unload (including the ability to store or consume) the Deficit Tonnage. The freight charges for transporting such Deficit Tonnage shall be the Effective Rate applicable in the calendar quarter that the Deficit Tonnage accrued. * BNSF will use best efforts to ship tonnage above Declared Annual Volume but no liquidated damages will be due on Deficit Tonnage above the Declared Annual Volume. SECTION 8. FURNISHING OF SHIPMENTS; CONFLICTING TERMS IN BILLS OF LADING. OTP shall arrange for shipments of Coal to be furnished to BNSF on a standard bill of lading in accordance with the Uniform Straight Bill of Lading or other shipping documents approved by BNSF, subject to the conditions of this Agreement. Each bill of lading or shipping document shall contain a reference to the contract number assigned to this Agreement, i.e., BNSF-C-12221. The rates identified in this Agreement shall not appear on the bill of lading. In the event there is a conflict between the terms of this Agreement, the terms of a bill of lading or other shipping documents, the terms of this Agreement shall govern and control. CONFIDENTIAL CONTRACT BNSF-C-12221 Page 6 of 15 07/15/1999 at 1:56 PM SECTION 9. WEIGHING 9(A) Weighing. The parties agree that the weight of the Coal in the Coal Cars will be determined at Origin by OTP's Origin Mine operator. BNSF shall not be responsible for such weight determinations. The weights ascertained by said operators shall be used for the assessment of the freight charges hereunder pursuant to Subsection 11(J). Weighing shall be performed on scales inspected semi-annually in accordance with the then-current AAR Scale Handbook specifications for such scales, and subject to supervision and verification by BNSF or BNSF's agent. 9(B) Breakdown Of Scales. If weights cannot be determined due to a breakdown of the scales at Origin, the weight per Train to be used for the assessment of freight charges hereunder shall be determined by averaging the per Car weights on the ten (10) immediately preceding weighed shipments (containing similar capacity Coal Cars) from the same Origin to Destination, adjusted for any variance in the number of Cars per shipment. If scales are determined by a scale test to be in error in excess of the AAR Scale Handbook tolerance of one percent (1.0%), said scales shall be recalibrated to be within one percent. The weights used by BNSF for purpose of assessing freight charges for Coal transported pursuant to this Agreement during the period since the last preceding inspection and calibration of such scales shall be used without any resulting payments or refunds. 9(C) Gross Load Limit and Overloads. If a loaded Coal Car is found by BNSF to weigh in excess of the maximum gross load limit for Cars or weighs in excess of the maximum gross weight on rail of 286,000 pounds, BNSF shall, if necessary, switch said overloaded Coal Car and remove it from the Train. BNSF retains the right to refuse to accept or transport overloaded Cars. BNSF shall not be obligated to reduce the lading of such Cars, which obligation is solely OTP's under this Agreement. After OTP, at no expense to BNSF, causes any excess Coal to be removed from the overloaded Coal Car, BNSF shall replace the Coal Car into the Train. For such services in removing and replacing each such Coal Car, OTP shall pay a switch charge to BNSF of *. If the excess Coal is removed during the Free Time at Origin without removing the Coal Car from a Train, there shall be no charge to OTP. BNSF reserves the right to increase the maximum gross weight on rail above 286,000 pounds and will notify OTP in writing of any increases in the maximum gross weight standard. SECTION 10. LOADING AND UNLOADING 10(A) Loading. * CONFIDENTIAL CONTRACT BNSF-C-12221 Page 7 of 15 07/15/1999 at 1:56 PM BNSF receives notice from OTP or its Origin Mine operator that the Train is released for movement back to Destination. However, if two or more Unit Trains are halted or delayed due to any cause attributable to BNSF, OTP shall be allowed additional Free Time at Origin until such time as the Bunched Unit Train is actually placed for loading, whereupon the Free Time at Origin will commence. 10(B) Advance Notice of Unloading. BNSF shall notify OTP's dumper building personnel at Destination of the estimated time of arrival of each Train at least four (4) hours prior to such estimated time of arrival at Destination. Normally, BNSF will telephone OTP; however, in the future and when installed, BNSF may make notification by electronic mail and/or BNSF installed software with the approval of OTP. 10(C) Unloading. * 10(D) Extended Unloading. OTP shall have unlimited Free Time to unload each Unit Train upon OTP's election to pay a release of power fee of * per train ("Extended Unloading"). The first three elections of Extended Unloading in each calendar year shall be free and without charge to OTP. OTP shall notify BNSF by fax or other electronic means of its election of Extended Unloading at the time of its election. OTP shall be responsible for the accounting of Extended Unloading charges and OTP shall pay to BNSF said charges within 30 days (and without BNSF billing) after the end of each calendar quarter. 10(E) Frozen Coal. If it is determined by OTP that Coal is frozen in the Coal Cars, OTP shall notify BNSF as soon as practical and OTP shall be granted as much Free Time as necessary to unload the Unit Train. 10(F) Residual Coal. As used in this Agreement, Residual Coal means Coal which remains in a Coal Car after the completion of the unloading process at Destination, including Coal which remains in a Coal Car after OTP has attempted to loosen or thaw frozen Coal. OTP will be responsible for the complete unloading of Coal Cars prior to departure of an empty Train from Destination. If BNSF discovers Residual Coal in any Coal Car in the Train after such Train has departed Destination, and such Residual Coal results in an unsafe condition (e.g., Residual Coal accumulated on one side or end of Car causing the Coal Car to become unstable), BNSF may remove such Coal Car from the Train at a charge to OTP of * per hour or fraction thereof for the removal service, such charge to include the return of such Coal Car to the Train after OTP has advised BNSF that such Coal Car has been made safe for movement. CONFIDENTIAL CONTRACT BNSF-C-12221 Page 8 of 15 07/15/1999 at 1:56 PM SECTION 11. SUPPLY OF EQUIPMENT AND SERVICE; MAINTENANCE; CAR DAMAGE AND DESTRUCTION; MINIMUM TRAIN SIZE 11(A) Applicable Rules. The parties agree that each party hereto will assume separate responsibilities for the Coal Cars as those responsibilities are designated in the Field Manual of Interchange Rules and Office Manual of the Interchange Rules adopted by the Association of American Railroads ("AAR Interchange Rules") presently in effect and as they may be changed hereafter from time to time. The parties further agree to comply with any rules and regulations of the Federal Railroad Administration applicable to such Coal Cars. Notwithstanding any provision to the contrary, BNSF shall not be liable for any loss of or damage to Coal or OTP's Coal Cars due to defects in said Coal Cars or due to improper loading thereof, or to defects in manufacture, design or workmanship. 11(B) Damage to Coal Cars. If OTP furnished Coal Cars are damaged under circumstances in which the AAR Interchange Rules make BNSF responsible for such damage, BNSF will give OTP written notification of the damage and will provide the Car initial and numbers. BNSF will repair or cause to be repaired such damaged Coal Cars at its expense and shall transport such Coal Cars for repairs and return them to Train service pursuant to the AAR Interchange Rules. BNSF shall do so and will use its best efforts to make such repairs in a timely fashion. While said Coal Cars are being repaired, BNSF shall furnish suitable substitute Coal Cars for use hereunder at no cost to OTP until said Coal Cars are repaired and returned to service, PROVIDED, HOWEVER, that if, at OTP's request, said Coal Cars are repaired at a shop of OTP's choosing, BNSF shall furnish suitable substitute Coal Cars until damaged Coal Cars are repaired and returned to service or until 365 days from the date of damage, whichever event occurs first. 11(C) Destruction of Coal Cars. In the event that Coal Cars are destroyed under circumstances in which the AAR Interchange Rules make BNSF responsible for such destruction, BNSF will give OTP written notification of such destruction and provide the Coal Car initials and numbers of each affected Coal Car. BNSF shall furnish suitable substitute Coal Cars, for use hereunder at no cost to OTP for a period not to exceed 365 days following the date BNSF furnishes suitable substitute Coal Cars or until the date replacement Coal Cars are in service. Settlement to OTP for any such destroyed Coal Car shall be in accordance with the applicable rule(s) of the Field Manual of the AAR Interchange Rules in effect on the date of such destruction. Such amounts so determined and undisputed will be paid to OTP within thirty (30) days of BNSF's receipt of OTP's invoice therefor. 11(D) Substitute Coal Cars. For the purpose of Subsections 11(B) and 11(C) "suitable substitute Coal Cars" shall mean open top, bottom dump, Coal Cars of approximately 100 Ton lading capacity which are compatible with Hoot Lake's unload facility. 11(E) Removal and Replacement of Cars for Storage or Maintenance. Upon request of OTP, BNSF will, on the return movement from Destination to Origin, stop a Train at a OTP designated maintenance facility at an intermediate point on the Route of Movement where track is available to remove or replace Cars from such Train. OTP shall pay BNSF a switching charge for removal and replacement of Coal Cars in such Train of * per hour, or fraction thereof, to be computed from the time the Train stops for removal or replacement of individual Coal Cars until such time as the last Coal Car is removed from the Train or until the last Coal Car is placed into the Train. 11(F) Removal and Replacement of Trains for Storage or Maintenance. Upon request of OTP, BNSF will, on the return movement from Destination to Origin, place an entire empty Train at a OTP designated maintenance facility at an intermediate point on the Route of Movement. Upon subsequent request of OTP, BNSF will remove the entire Train from such maintenance facility and return it to service. OTP will pay * in total to BNSF for its services in placing such Train at such maintenance facility and removing such Train from such maintenance CONFIDENTIAL CONTRACT BNSF-C-12221 Page 9 of 15 07/15/1999 at 1:56 PM facility and returning it to service. In addition, OTP shall pay BNSF at the rate of * per hour required for such placement or removal, with such charges to commence when the Train crew starts such placement and ends when the Train is set for departure. 11(G) Switching to Connecting Rail Carrier. If a Car maintenance facility selected by OTP is served by another rail carrier which necessitates, at an intermediate point on the Route of Movement, a switch movement of Coal Cars, or a switch movement of a Train, to or from a connecting railroad, BNSF will provide the necessary switching services. BNSF will be paid by OTP in accordance with Subsection 11(E) for a switch movement of Coal Cars, and in accordance with Subsection 12(B) for a switch movement of Trains. Any switching or any other charges imposed by the connecting railroad shall be paid by OTP. 11(H) Maintenance Facility Off Route of Movement If a Car maintenance facility selected by OTP is located at a point which is not on the Route of Movement, BNSF will be paid the following line-haul charge, covering any movement on the BNSF system not on the Route of Movement, in addition to the charges specified in Subsections 11(E), 11(F) or 11(G), as appropriate: Rates in Dollars Per Car, Per Mile, Minimum 75 Miles Number of Coal Cars --------------------------------------------------- * 25 or Less * 26 to 75 * More Than 75 The charges set out in Subsections 11(E), 11(F), 11(G) and 11(H) shall not apply to the movement of Coal Cars damaged by BNSF to a maintenance facility for repair. 11(I) Bad Order Switching. No charges will be assessed by BNSF for switching occasioned by bad ordering of Coal Cars by BNSF personnel, including both switching out of bad ordered Coal Cars and/or switching in of spare Coal Cars in substitution for bad ordered Coal Cars. 11(J) Minimum Train Size. (1) Minimum Tender: Each Train furnished at Origin for loading shall contain no less than 113 Cars ("Minimum Train Size"), except as provided in this Section 11. The weight for determination of freight charges shall be the greater of (1) the actual weight of the lading of the Train as determined pursuant to Section 9; or (2) 97 tons per Car times 113 Coal Cars in the Train (except as provided in Section 11(J) herein). (2) Damaged or Destroyed Cars Exception: If OTP is prevented from furnishing at least 113 Coal Cars because its Coal Cars have been damaged or destroyed by BNSF and BNSF is liable therefor, and if BNSF is unable to furnish sufficient suitable substitute Coal Cars pursuant to Subsections 11(B), 11(C) and 11(D), Minimum Train Size shall be reduced to the number of suitable Coal Cars OTP and BNSF together are able to provide; however, the Minimum Train Size under this Subsection (J)(2) shall be 75 Coal Cars. (3) En Route Exception: In the event OTP is unable to furnish at least 113 Coal Cars because certain Coal Cars are found en route or at Origin to be unsuitable for loading, excluding open doors which can be secured, the Minimum Train Size shall be reduced by the number of Coal Cars found to be unsuitable for loading; however, the Minimum Train Size under this Subsection 11(J)(3) shall be 100 Coal Cars. (4) Insufficient BNSF Substitute Cars: If OTP's Coal Cars are damaged or destroyed by BNSF and BNSF is unable to furnish sufficient suitable substitute Coal Cars as provided for in Subsections 11(B), 11(C), and 11(D) the Minimum Annual Volume shall be reduced by 97 Tons CONFIDENTIAL CONTRACT BNSF-C-12221 Page 10 of 15 07/15/1999 at 1:56 PM for each Coal Car less than 113 in any Train shipment resulting from BNSF's inability to furnish suitable substitute Coal Cars. (5) Insufficient OTP Substitute Cars: If, due only to the unexcused fault of OTP, sufficient Coal Cars are not available for loading to meet the Minimum Train Size, BNSF will accept loaded Coal Cars furnished for transportation and the Effective Rate shall be assessed on actual Tons loaded plus 97 Tons per Coal Car for each Car short of the Minimum Train Size. Such Tons which are not actually moved but for which charges are paid pursuant to this Subsection 11(J)(5) will be considered as Tons received in meeting the Minimum Annual Volume and the Declared Quarterly Volume. OTP will use reasonable efforts to maximize the tonnage per Car and, BNSF and OTP will use reasonable efforts to maximize the number of Cars in each train. SECTION 12. HOLDING OF EMPTY TRAINS 12(A) Storage On the Route of Movement. If storage track is available at a location on the Route of Movement (for Train storage at Destination, see Section 10(D)), upon request of OTP, BNSF will, on the return movement from Destination to Origin, move an empty Train to such storage track and place the Train there for storage. BNSF will be paid * in total (billable at the time the Train is placed) for its services in placing and removing such Train. In addition, OTP shall pay a storage charge of * for each 24 hour period or fraction thereof that the Train is stored on any such storage track owned by BNSF. 12(B) Switching to Connecting Carrier. OTP shall pay * per Train for each switch to or from a connecting carrier. In addition, OTP shall pay BNSF at the rate of * per hour required for any such switching, with such charges to commence when the Train crew starts such switching and shall end when the last car is released to the connecting railroad by BNSF. Any switching or other charges imposed by the connecting railroad shall be paid by OTP. However, none of the charges in this Subsection 12(B) shall apply if such switch is for the purpose of continuing the movement of Unit Trains on the Route of Movement. 12(C) Storage Off Route of Movement. If OTP's owned or leased storage track is located at a point which is not on the Route of Movement, BNSF will move OTP's Trains to and from such storage track and OTP shall pay the line haul charges specified in Subsection 11(H) for any such movement on the BNSF system in addition to the charges specified in Subsection 12(B) as appropriate. If OTP elects to move consist sizes of * cars or more from the state of Illinois to Wyoming Mines origins, or from Wyoming Mines to the state of Illinois, a total charge of * per car will be applicable and the charges specified in Subsection 11(H) and Subsection 12(B) shall not apply. SECTION 13. BILLING AND PAYMENT All undisputed payments for transportation of Coal due hereunder shall be due and payable on or within five (5) working days of the receipt of a written or electronic statement of charge or charges, with the exception of ancillary charges specified in Subsection 7(C) and 7(D) which shall be due within 30 calendar days of receipt. OTP shall make all payments to BNSF for transportation of Coal under this Agreement by wire transfer or by electronic funds transfer. Other charges due to BNSF by OTP or OTP by BNSF may be paid by mail. OTP will audit freight bills and contact, if necessary, a BNSF Accounting Department representative assigned to OTP's account, to make corrections or adjustments to bills prior to the wire transfer. If corrections or adjustments to freight bills cannot be agreed upon within said 5 day period, OTP shall wire transfer the undisputed amounts billed, and the balance, if any, will be transferred within 5 calendar days of the date the parties agree as to the appropriate corrections or adjustments. When resolved, by agreement, the balance owing, if any, shall be accompanied by interest at 10% per annum on the unpaid balance from the date the original bill was partially unpaid to the date of the wire transfer of the agreed balance. CONFIDENTIAL CONTRACT BNSF-C-12221 Page 11 of 15 07/15/1999 at 1:56 PM If a party fails to make undisputed payments for Coal transportation on or within 5 working days of receipt of written statements of charge or charges, or fails to make undisputed payment for ancillary charges within 30 calendar days of receipt, it agrees to pay a late charge to compensate the other party for its administrative costs at a rate of two percent (2%) of any amount due and unpaid, for each 30 day period or portion thereof, or at the maximum rate permitted by law, if lower, commencing from the expiration of said 10 working days or 30 calendar days, respectively, of receipt of written statement of such freight charges or ancillary charges. SECTION 14. FORCE MAJEURE 14(A) Defined. The term "Force Majeure" as used herein shall mean any cause or causes beyond the reasonable control of the party affected thereby which, by exercise of due diligence, it shall be unable to overcome, including, without limitation: Acts of God; acts of the public enemy; blockades; strikes; lockouts; labor disputes or other industrial disturbances; riots; disorders; storms; landslides; floods; washouts; earthquake; lightning; unusually large snow accumulation; civil disturbances; restraint, acts or decisions by court or governmental or other public authority directly affecting either party; boycotts; embargoes, including embargoes pursuant to AAR service orders; war or acts of military authorities; unavailability of diesel fuel for locomotives or generator start-up; derailments; failure of mine operators to supply coal (whether excused by reason of a Force Majeure condition under OTP's coal purchase contract with such mine operator; or unexcused and in violation of such contract); frozen coal; or fire or explosion or mechanical breakdown or damage affecting BNSF's facilities or equipment, availability of Coal Cars from manufacturers, OTP's Hoot Lake Steam Plant or equipment or facilities related thereto including the Unloading Facilities, or affecting the mine(s) of OTP's coal supplier(s), or equipment or facilities related thereto, including Loading Facilities (extending for periods beyond one hour, including emergency outages of equipment or facilities for the purpose of making repairs to avoid breakdown thereof or damage thereto other than regularly scheduled repairs or regular maintenance). 14(B) Effect Hereunder. If because of Force Majeure, either party hereto is unable to carry out its obligations under this Agreement, and if such party shall promptly give to the other party written notice of such Force Majeure, then the obligation of the party giving such notice shall be suspended to the extent made necessary by such Force Majeure and during its continuance. However, the party giving such notice shall use its best efforts to eliminate such Force Majeure insofar as possible with a minimum of delay, and thereupon promptly give notice to the other party when the Force Majeure has terminated. Nothing herein contained shall cause the party affected by an event of Force Majeure to submit to what it believes to be an unfavorable labor agreement, and it is agreed that any settlement of labor strikes or differences with workmen shall be entirely within the sole discretion of the affected party. 14(C) Effect on Minimum Annual Volume. In the event shipments of Coal cannot be made due to Force Majeure, as defined in this Section affecting either party, the Minimum Annual Volume shall be reduced by 1/365th for each day during which the event of Force Majeure continues. The above reductions shall take into account the effects of partial and full disability events. Any day in which two or more such events occur shall be considered as one day. An event of Force Majeure shall last for a continuous 24 hour period before the Minimum Annual Volume shall be reduced. Force Majeure days shall not be carried over into succeeding years for purposes of calculating compliance with the Minimum Annual Volume. SECTION 15. LIMITATIONS ON ACTIONS FOR COAL LOSS OR DAMAGE 15(A) Liability. Standard common carrier liability pursuant to 49 U.S.C. Section 11706 shall apply to loss of or damage to the Coal being transported pursuant to this Agreement. In the event of a conflict between said terms and this Agreement, this Agreement shall govern. CONFIDENTIAL CONTRACT BNSF-C-12221 Page 12 of 15 07/15/1999 at 1:56 PM 15(B) Claims. Claims for loss of or damage to Coal en route must be made in writing by OTP to BNSF within 9 months after receipt of BNSF's written statement of charges for transporting such Coal. Suits must be filed against BNSF within two years and one day from the day when notice in writing from BNSF is received by OTP stating that BNSF has disallowed OTP's claim or any part or parts thereof as specified in BNSF's notice. If claims are not made and/or suits are not instituted thereon in accordance with the foregoing provisions, BNSF shall not be liable and such claims will not be paid. This Subsection 15(B) shall not apply in the event of a material breach of this Agreement by BNSF. This Subsection 15(B) shall only apply to loss of or damage to Coal which occurs while such Coal is being transported by BNSF between Origin and Destination. SECTION 16. TERMINATION If either party hereto shall default in any material obligation of this Agreement which is not excused as Force Majeure as defined in Section 14, and continues in such default for a period of sixty (60) days after written notice thereof is given by the non-defaulting party to such other party of the existence of such default, or, if more than sixty (60) days are required to correct with reasonable diligence the default set forth in said notice and such defaulting party shall fail within said sixty (60) day period to commence the action necessary to correct such matters and thereafter prosecute the same to completion with reasonable diligence, the non- defaulting party may, at its option, and without prejudice to its other rights and remedies hereunder, at law or in equity, terminate this Agreement by written notice thereof to the party in default. SECTION 17. ASSIGNMENT AND BINDING EFFECT This Agreement shall bind and inure to the benefit of the parties and their successors and assigns. Either party hereto may assign any receivable due them under this Agreement, provided however, such assignment shall not relieve the assignor of any of its rights or obligations under this Agreement. With the exception of assignment of: (a) said receivables; or (b) either party's right to assign to a successor where such assignment or delegation occurs by way of sale or transfer of all or substantially all of a party's assets by way of merger, consolidation, or combination; neither party may assign this Agreement or any other rights or obligations hereunder without the prior written consent of the other party; provided however, that such written consent shall not be unreasonably withheld and that no assignment shall be effective unless and until the assignee shall assume in writing the obligation of the assignor. SECTION. 18. ENTIRETY AND AMENDMENTS This Agreement comprises the entire Agreement, and merges and supersedes all prior oral and written understandings and representations between OTP and BNSF concerning the subject matter hereof. All amendments of the terms of this Agreement shall be in writing, signed by the parties hereto and shall comply with any applicable laws and regulations. SECTION 19. WAIVERS AND REMEDIES The failure of either party hereto to insist in any one or more instances upon strict performance of any of the obligations of the other party pursuant to this Agreement or to take advantage of any of its rights hereunder shall not be construed as a waiver of the performance of any such obligation or the relinquishment of any such rights for the future, but the same shall continue and remain in full force and effect. Upon a material breach of this Agreement, all remedies provided by law or in equity, including specific performance of this Agreement, shall be available to the affected party. SECTION 20. NOTICE Any notice required or permitted hereunder, including an event of Force Majeure, except for invoices and payments and as otherwise provided in this Agreement, shall be made in writing and shall be deemed effective when delivered personally to the party to whom directed, or upon the earlier of actual receipt, or CONFIDENTIAL CONTRACT BNSF-C-12221 Page 13 of 15 07/15/1999 at 1:56 PM three days after deposit in the United States Mail, Registered or Certified Mail, return receipt requested with postage prepaid and property addressed to the following: The Burlington Northern and Santa Fe Railway Company Otter Tail Power Company ---------------------------- ------------------------ 2650 Lou Menk Drive 215 South Cascade Fort Worth, TX 76161-0051 Fergus Falls, MN 56537 Attn: Coal Business Unit Attn: Hoot Lake Plant These addresses may be changed by written notice to the other party. SECTION 21. LIABILITY AND INDEMNIFICATION 21(A) BNSF Indemnity. To the extent permitted by applicable law, BNSF shall protect, indemnify and save harmless OTP, its officers, directors, employees, agents and servants from and against all liabilities losses, claims, demands, damages, penalties, causes of action, judgments, suits, (including suits for personal injuries or death) including all reasonable attorneys' fees, court costs and expenses incurred in defense of any claim or suit, proximately caused by the negligent or intentional conduct of BNSF or its employees, representatives or agents and arising out of or in connection with its obligations under this Agreement, and shall pay for any losses, claims, demands, damages, penalties, judgments, suit of any nature rendered against OTP or such person. 21(B) OTP Indemnity. To the extent permitted by applicable law, OTP shall protect, indemnify and save harmless BNSF, its officers, directors, employees, agents and servants from and against all liabilities losses, claims, demands, damages, penalties, causes of action, judgments, suits, (including suits for personal injuries or death) including all reasonable attorneys' fees, court costs and expenses incurred in defense of any claim or suit, proximately caused by the negligent or intentional conduct of OTP or its employees, representatives or agents and arising out of or in connection with its obligations under this Agreement, and shall pay for any losses, claims, demands, damages, penalties, judgments, suit of any nature rendered against BNSF or such person. 21(C) Joint Indemnity. If any liability, loss, claim, damage, demand, penalty, cause of action, judgment or suit arises from the joint negligence or intentional conduct of BNSF and/or OTP and/or a third party, each party's responsibility for its portion of the liability, loss, claim, damage, penalty, cause of action, or suit shall be as determined in accordance will applicable law. SECTION 22. GOVERNING LAWS For all purposes, this Agreement shall be deemed to be an Agreement made in the state of Minnesota and governed by and construed according to the laws of that state except that matters related to loss and damage to coal shall be construed and interpreted consistent with relevant agency and court decisions and U.S. statutes and regulations thereunder establishing or determining rights and obligations of carriers providing interstate common carriage by rail. SECTION 23. CONFIDENTIALITY Except when required by law, the parties shall not reveal the terms of this Agreement to persons not employed by a party to this Agreement or its affiliate and shall protect the confidentiality of the information developed in connection with this Agreement; provided, however, that neither party will be precluded from revealing such information in obtaining or attempting to obtain financing or in filing reports and information CONFIDENTIAL CONTRACT BNSF-C-12221 Page 14 of 15 07/15/1999 at 1:56 PM with the Securities and Exchange Commission, or the appropriate governmental or regulatory authorities, or making public information required thereby, or when advised by legal counsel that such disclosure is required. When required, the parties may also submit information to consultants and contractors performing work related to this Agreement who agree in writing to protect the confidentiality of such information. SECTION 24. REPRESENTATIONS AND WARRANTIES 24(A) OTP represents and warrants to BNSF: (1) It is a corporation duly organized, validly existing and in good standing under the laws of the State of Minnesota. (2) The execution and delivery by OTP of this Agreement and the performance by OTP of its obligations are within its power and authority and have been duly authorized. (3) This Agreement is a legal, valid and binding obligation of OTP enforceable against OTP in accordance with its terms. 24(B) BNSF represents and warrants to OTP: (1) It is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware. (2) The execution and delivery of this Agreement by BNSF and the performance by BNSF of its obligations thereunder are within its corporate powers, have been duly authorized by all necessary corporate action, and do not and will not contravene or conflict with any provision of law or of its charter or by-laws. (3) This Agreement is legal, valid and binding obligation of BNSF enforceable against BNSF in accordance with its terms. SECTION 25. HEADINGS NOT TO AFFECT CONSTRUCTION The headings to the Sections, Subsection and paragraphs of this Agreement are inserted for the convenience of reference only, and are neither to be taken to be any part of the provisions hereof nor to control or affect the meaning, construction or effect of the same. IN WITNESS WHEREOF, the parties have executed this Agreement effective as of the date last written below. THE BURLINGTON NORTHERN OTTER TAIL POWER COMPANY AND SANTA FE RAILWAY COMPANY BY:/s/Ward Uggerud BY: /s/David S. Quilici - --------------------------------- ----------------------------- Chief Operating Officer, TITLE: Energy Supply TITLE: VP Coal Marketing - ---------------------------------- ----------------------------- DATE: July 16, 1999 DATE: 7-19-99 - ---------------------------------- ----------------------------- CONFIDENTIAL CONTRACT BNSF-C-12221 Page 15 of 15 07/15/1999 at 1:56 PM (*) Confidential information has been omitted and filed separately with the Commission pursuant to Rule 24b-2. EX-10 6 EXHIBIT 10-N-3 SEVERANCE AGREEMENT This Agreement is made as of the ________ day of ____________________, between Otter Tail Power Company, a Minnesota corporation, with its principal offices at 215 South Cascade Street, P.O. Box 496, Fergus Falls, Minnesota 56538-0496 (the "Company") and _____________________ ("Employee"), residing at __________________________________. W I T N E S S E T H T H A T: WHEREAS, this Agreement is intended to specify the financial arrangements that the Company will provide to Employee upon Employee's separation from employment with the Company under any of the circumstances described herein; and WHEREAS, this Agreement is entered into by the Company in the belief that it is in the best interests of the Company and its shareholders to provide stable conditions of employment for Employee notwithstanding the possibility, threat or occurrence of certain types of change in control, thereby enhancing the Company's ability to attract and retain highly qualified people. NOW, THEREFORE, to assure the Company that it will have the continued dedication of Employee notwithstanding the possibility, threat or occurrence of a bid to take over control of the Company, and to induce Employee to remain in the employ of the Company, and for other good and valuable consideration, the Company and Employee agree as follows: 1. Term of Agreement. The term of this Agreement shall commence on the date hereof as first written above and shall continue through April 1, 2001; provided that commencing on March 31, 2001 and each March 31 thereafter, the term of this Agreement shall automatically be extended for one additional year unless not later than December 31 of the preceding year, the Company shall have given notice that it does not wish to extend this Agreement; and provided, further, that notwithstanding any such notice by the Company not to extend, this Agreement shall continue in effect for a period of 24 months beyond the term provided herein if a Change in Control (as defined in Section 3(i) hereof) shall have occurred during such term. 2. Termination of Employment. -------------------------- (i) Prior to a Change in Control. Employee's rights upon termination of employment prior to a Change in Control (as defined in Section 3(i) hereof) shall be governed by the Company's standard employment termination policy applicable to Employee in effect at the time of termination. (ii) After a Change in Control. (a) From and after the date of a Change in Control (as defined in Section 3(i) hereof) during the term of this Agreement, the Company shall not terminate Employee from employment with the Company except as provided in this Section 2(ii) or as a result of Employee's Disability (as defined in Section 3(iv) hereof) or death. (b) From and after the date of a Change in Control (as defined in Section 3(i) hereof) during the term of this Agreement, the Company shall have the right to terminate Employee from employment with the Company at any time during the term of this Agreement for Cause (as defined in Section 3(iii) hereof), by written notice to Employee, specifying the particulars of the conduct of Employee forming the basis for such termination. (c) From and after the date of a Change in Control (as defined in Section 3(i) hereof) during the term of this Agreement: (x) the Company shall have the right to terminate Employee's employment without Cause (as defined in Section 3(iii) hereof), at any time; and (y) Employee shall, upon the occurrence of such a termination by the Company without Cause, or upon the voluntary termination of Employee's employment by Employee for Good Reason (as defined in Section 3(ii) hereof), be entitled to receive the benefits provided in Section 4 hereof. Employee shall evidence a voluntary termination for Good Reason by written notice to the Company given within 60 days after the date of the occurrence of any event that Employee knows or should reasonably have known constitutes Good Reason for voluntary termination. Such notice need only identify Employee and set forth in reasonable detail the facts and circumstances claimed by Employee to constitute Good Reason. Any notice given by Employee pursuant to this Section 2 shall be effective five business days after the date it is given by Employee. 3. Definitions ----------- (i) A "Change in Control" shall mean: (a) a change in control of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A promulgated under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), or successor provision thereto, whether or not the Company is then subject to such reporting requirement; (b) any "person" (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) is or becomes the "beneficial owner" (as defined in Rule 13d-3 promulgated under the Exchange Act), directly or indirectly, of securities of the Company representing 35% or more of the combined voting power of the Company's then outstanding securities; (c) the Continuing Directors (as defined in Section 3(v) hereof) cease to constitute a majority of the Company's Board of Directors; provided that such change is the direct or indirect result of a proxy fight and contested election or elections for positions on the Board of Directors; or (d) the majority of the Continuing Directors (as defined in Section 3(v) hereof) determine in their sole and absolute discretion that there has been a change in control of the Company. (ii) "Good Reason" shall mean the occurrence of any of the following events, except for the occurrence of such an event in connection with the termination or reassignment of Employee's employment by the Company for Cause (as defined in Section 3(iii) hereof), for Disability (as defined in Section 3(iv) hereof) or for death: (a) the assignment to Employee of employment responsibilities which are not of comparable responsibility and status as the employment responsibilities held by Employee immediately prior to a Change in Control; (b) a reduction by the Company in Employee's base salary as in effect immediately prior to a Change in Control; (c) an amendment or modification of the Company's incentive compensation program (except as may be required by applicable law) which affects the terms or administration of the program in a manner adverse to the interest of Employee as compared to the terms and administration of such program immediately prior to a Change in Control; (d) the Company's requiring Employee to be based anywhere other than within 50 miles of Employee's office location immediately prior to a Change in Control, except for requirements of temporary travel on the Company's business to an extent substantially consistent with Employee's business travel obligations immediately prior to a Change in Control; (e) except to the extent otherwise required by applicable law, the failure by the Company to continue in effect any benefit or compensation plan, stock ownership plan, stock purchase plan, stock incentive plan, bonus plan, life insurance plan, health-and-accident plan, or disability plan in which Employee is participating immediately prior to a Change in Control (or plans providing Employee with substantially similar benefits), the taking of any action by the Company which would adversely affect Employee's participation in, or materially reduce Employee's benefits under, any of such plans or deprive Employee of any material fringe benefit enjoyed by Employee immediately prior to such Change in Control, or the failure by the Company to provide Employee with the number of paid vacation days to which Employee is entitled immediately prior to such Change in Control in accordance with the Company's vacation policy as then in effect; or (f) the failure by the Company to obtain, as specified in Section 6(i) hereof, an assumption of the obligations of the Company to perform this Agreement by any successor to the Company. (iii) "Cause" shall mean termination by the Company of Employee's employment based upon (a) the willful and continued failure by Employee substantially to perform Employee's duties and obligations (other than any such failure resulting from Employee's incapacity due to physical or mental illness or any such actual or anticipated failure resulting from Employee's termination for Good Reason) or (b) the willful engaging by Employee in misconduct which is materially injurious to the Company, monetarily or otherwise. For purposes of this Section 3(iii), no action or failure to act on Employee's part shall be considered "willful" unless done, or omitted to be done, by Employee in bad faith and without reasonable belief that such action or omission was in the best interests of the Company. (iv) "Disability" shall mean any physical or mental condition which would qualify Employee for a disability benefit under the Company's long- term disability plan. (v) "Continuing Director" shall mean any person who is a member of the Board of Directors of the Company, while such person is a member of the Board of Directors, who is not an Acquiring Person (as hereinafter defined) or an Affiliate or Associate (as hereinafter defined) of an Acquiring Person, or a representative of an Acquiring Person or of any such Affiliate or Associate, and who (a) was a member of the Board of Directors on the date of this Agreement as first written above or (b) subsequently becomes a member of the Board of Directors, if such person's nomination for election or initial election to the Board of Directors is recommended or approved by a majority of the Continuing Directors. For purposes of this Section 3(v): "Acquiring Person" shall mean any "person" (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) who or which, together with all Affiliates and Associates of such person, is the "beneficial owner" (as defined in Rule 13d-3 promulgated under the Exchange Act) of 20% or more of the shares of Common Stock of the Company then outstanding, but shall not include the Company, any subsidiary of the Company or any employee benefit plan of the Company or of any subsidiary of the Company or any entity holding shares of Common Stock organized, appointed or established for, or pursuant to the terms of, any such plan; and "Affiliate" and "Associate" shall have the respective meanings ascribed to such terms in Rule 12b-2 promulgated under the Exchange Act. 4. Benefits upon Termination under Section 2(ii)(c) ------------------------------------------------ (i) Upon the termination (voluntary or involuntary) of the employment of Employee pursuant to Section 2(ii)(c) hereof, Employee shall be entitled to receive the benefits specified in this Section 4. The amounts due to Employee under subparagraph (a) of this Section 4(i) shall be paid to Employee, at Employee's election as specified in a written notice delivered by Employee to the Company on the date of this Agreement and which is attached hereto as Exhibit A and made a part hereof, either (a) in a lump sum not later than one business day prior to the date that the termination of Employee's employment becomes effective or (b) in 36 equal installments payable monthly, on the last business day of the month, for 36 consecutive months following the date that the termination of Employee's employment becomes effective. The amounts due to Employee under subparagraphs (b), (c) and (d) of this Section 4(i) shall be paid to Employee not later than one business day prior to the date that the termination of Employee's employment becomes effective. Subject to the provisions of Section 4(ii) hereof, all benefits to Employee pursuant to this Section 4(i) shall be subject to any applicable payroll or other taxes required by law to be withheld. (a) The Company shall pay as severance pay to Employee an amount equal to three times the sum of (1) Employee's highest annual rate of salary from the Company in effect at any time during the 36 months preceding the date that the termination of Employee's employment became effective and (2) the average of the annual bonus paid or to be paid to Employee in respect of each of the three fiscal years preceding the fiscal year when the termination of Employee's employment became effective. (b) For a period of 36 months following the date that the termination of Employee's employment became effective or until Employee reaches age 65 or dies, whichever is the shorter period, the Company shall continue for Employee, at the Company's expense, the health, disability and life insurance coverage in effect for Employee immediately prior to the date that the termination of Employee's employment became effective under the plans provided by the Company for its executive personnel generally or, if such coverage cannot by the terms of such plans be provided thereunder, then the Company shall provide equivalent insurance coverage for Employee for such period under specially obtained policies of insurance. (c) The Company shall pay to Employee (1) any amount earned by Employee as a bonus with respect to the fiscal year of the Company preceding the termination of Employee's employment if such bonus has not theretofore been paid to Employee, and (2) an amount representing credit for any vacation earned or accrued by him but not taken. (d) The Company shall also pay to Employee all legal fees and expenses incurred by Employee as a result of such termination of employment (including all fees and expenses, if any, incurred by Employee in seeking to obtain or enforce any right or benefit provided to Employee by this Agreement whether by arbitration or otherwise); and (e) Any and all contracts, agreements or arrangements between the Company and Employee prohibiting or restricting Employee from owning, operating, participating in, or providing employment or consulting services to, any business or company competitive with the Company at any time or during any period after the date the termination of Employee's employment becomes effective, shall be deemed terminated and of no further force or effect as of the date the termination of Employee's employment becomes effective, to the extent, but only to the extent, such contracts, agreements or arrangements so prohibit or restrict Employee; provided that the foregoing provision shall not constitute a license or right to use any proprietary information of the Company and shall in no way affect any such contracts, agreements or arrangements insofar as they relate to nondisclosure and nonuse of proprietary information of the Company notwithstanding the fact that such nondisclosure and nonuse may prohibit or restrict Employee in certain competitive activities. (ii) In the event that any payment or benefit received or to be received by Employee in connection with a Change in Control of the Company or termination of Employee's employment (whether payable pursuant to the terms of this Agreement or any other plan, contract, agreement or arrangement with the Company, with any person whose actions result in a Change in Control of the Company or with any person constituting a member of an "affiliated group" as defined in Section 280G(d)(5) of the Internal Revenue Code of 1986, as amended (the "Code"), with the Company or with any person whose actions result in a Change in Control of the Company (collectively, the "Total Payments")) would be subject to the excise tax imposed by Section 4999 of the Code or any interest, penalties or additions to tax with respect to such excise tax (such excise tax, together with any such interest, penalties or additions to tax, are collectively referred to as the "Excise Tax"), then Employee shall be entitled to receive from the Company an additional cash payment (a "Gross-Up Payment") within thirty business days of such determination in an amount such that after payment by Employee of all taxes (including any interest, penalties or additions to tax imposed with respect to such taxes), including any Excise Tax, imposed upon the Gross-Up Payment, Employee retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Total Payments. All determinations required to be made under this Section 4(ii), including whether a Gross-Up Payment is required and the amount of such Gross-Up Payment, shall be made by the independent accounting firm retained by the Company on the date of the Change in Control (the "Accounting Firm"), which shall provide detailed supporting calculations both to the Company and Employee within 15 business days of the date that the termination of Employee's employment becomes effective, or such earlier time as is requested by the Company. If the Accounting Firm determines that no Excise Tax is payable by Employee, it shall furnish Employee with an opinion that Employee has substantial authority not to report any Excise Tax on Employee's federal income tax return. Any uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder shall be resolved in favor of Employee. As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder, it is possible that at a later time there will be a determination that the Gross-Up Payments made by the Company were less than the Gross-Up Payments that should have been made by the Company ("Underpayment"), consistent with the calculations required to be made hereunder. In the event that Employee is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment, if any, that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of Employee. As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder, it is possible that at a later time there will be a determination that the Gross-Up Payments made by the Company were more than the Gross-Up Payments that should have been made by the Company ("Overpayment"), consistent with the calculations required to be made hereunder. Employee agrees to refund to the Company the amount of any Overpayment that the Accounting Firm shall determine has occurred hereunder. Any determination by the Accounting firm as to the amount of any Gross-Up Payment, including the amount of any Underpayment or Overpayment, shall be binding upon the Company and Employee. (iii) Any payment not made to Employee when due hereunder shall thereafter, until paid in full, bear interest at the rate of interest equal to the reference rate announced from time to time by U.S. Bank National Association, plus two percent, with such interest to be paid to Employee upon demand or monthly in the absence of a demand. (iv) Employee shall not be required to mitigate the amount of any payment provided for in this Section 4 by seeking other employment or otherwise. The amount of any payment or benefit provided in this Section 4 shall not be reduced by any compensation earned by Employee as a result of any employment by another employer. 5. Employee's Agreements. ---------------------- Employee agrees that: (i) Without the consent of the Company, Employee will not terminate employment with the Company without giving 60 days prior notice to the Company, and during such 60-day period Employee will assist the Company, as and to the extent reasonably requested by the Company, in training the successor to Employee's position with the Company. The provisions of this Section 5(i) shall not apply to any termination (voluntary or involuntary) of the employment of Employee pursuant to Section 2(ii)(c) hereof. (ii) Without the consent of the Company or except as may be required by law, Employee will not at any time after termination of his employment with the Company disclose to any person, corporation, firm, or other entity, confidential information concerning the Company of which Employee has gained knowledge during employment with the Company. (iii) In the event that Employee has received any benefits from the Company under Section 4 of this Agreement, then, during the period of 36 months following the date that the termination of Employee's employment became effective, Employee, upon request by the Company: (a) Will consult with one or more of the executive officers concerning the business and affairs of the Company for not to exceed four hours in any month at times and places selected by Employee as being convenient to him, all without compensation other than what is provided for in Section 4 of this Agreement; and (b) Will testify as a witness on behalf of the Company in any legal proceedings involving the Company which arise out of events or circumstances that occurred or existed prior to the date that the termination of Employee's employment became effective (except for any such proceedings relating to this Agreement), without compensation other than what is provided for in Section 4 of this Agreement, provided that all out- of-pocket expenses incurred by Employee in connection with serving as a witness shall be paid by the Company. Employee shall not required to perform Employee's obligations under this Section 5(iii) if and so long as the Company is in default with respect to performance of any of its obligations under this Agreement. 6. Successors and Binding Agreement. --------------------------------- (i) The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise to all or substantially all of the business and/or assets of the Company), by agreement in form and substance satisfactory to Employee, to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. Failure of the Company to obtain such agreement prior to the effectiveness of any such succession shall be a breach of this Agreement and shall entitle Employee to compensation from the Company in the same amount and on the same terms as Employee would be entitled hereunder if employee terminated employment after a Change in Control for Good Reason, except that for purposes of implementing the foregoing, the date on which any such succession becomes effective shall be deemed the date that the termination of Employee's employment becomes effective. As used in this Agreement, "Company" shall mean the Company and any successor to its business and/or assets which executes and delivers the agreement provided for in this Section 6(i) or which otherwise becomes bound by all the terms and provisions of this Agreement by operation of law. (ii) This Agreement is personal to Employee, and Employee may not assign or transfer any part of Employee's rights or duties hereunder, or any compensation due to him hereunder, to any other person. Notwithstanding the foregoing, this Agreement shall inure to the benefit of and be enforceable by Employee's personal or legal representatives, executors, administrators, heirs, distributees, devisees, and legatees. 7. Arbitration. Any dispute or controversy arising under or in connection with this Agreement shall be settled exclusively by arbitration in the Fergus Falls area, in accordance with the applicable rules of the American Arbitration Association then in effect. Judgment may be entered on the arbitrator's award in any court having jurisdiction. 8. Modification; Waiver. No provisions of this Agreement may be modified, waived, or discharged unless such waiver, modification, or discharge is agreed to in a writing signed by Employee and such officer as may be specifically designated by the Board of Directors of the Company. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. 9. Notice. All notices, requests, demands, and all other communications required or permitted by either party to the other party by this Agreement (including, without limitation, any notice of termination of employment and any notice of an intention to arbitrate) shall be in writing and shall be deemed to have been duly given when delivered personally or received by certified or registered mail, return receipt requested, postage prepaid, at the address of the other party, as first written above (directed to the attention of the Board of Directors and Corporate Secretary in the case of the Company). Either party hereto may change its address for purposes of this Section 9 by giving 15 days' prior notice to the other party hereto. 10. Severability. If any term or provision of this Agreement or the application hereof to any person or circumstances shall to any extent be invalid or unenforceable, the remainder of this Agreement or the application of such term or provision to persons or circumstances other than those as to which it is held invalid or unenforceable shall not be affected thereby, and each term and provision of this Agreement shall be valid and enforceable to the fullest extent permitted by law. 11. Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument. 12. Governing Law. This Agreement has been executed and delivered in the State of Minnesota and shall, in all respects, be governed by, and construed and enforced in accordance with, the laws of the State of Minnesota, including all matters of construction, validity and performance. 13. Effect of Agreement; Entire Agreement. The Company and Employee understand and agree that this Agreement is intended to reflect their agreement only with respect to payments and benefits upon termination in certain cases and is not intended to create any obligation on the part of either party to continue employment. This Agreement supersedes any and all other oral or written agreements or policies made relating to the subject matter hereof and constitutes the entire agreement of the parties relating to the subject matter hereof; provided that this Agreement shall not supersede or limit in any way Employee's rights under any benefit plan, program or arrangements in accordance with their terms. 14. ERISA. For purposes of the Employee Retirement Income Security Act of 1974, this Agreement is intended to be a severance pay employee welfare benefit plan, and not an employee pension benefit plan, and shall be construed and administered with that intention. IN WITNESS WHEREOF, the Company has caused this Agreement to be executed in its name by a duly authorized director and officer, and Employee has hereunto set his or her hand, all as of the date first written above. OTTER TAIL POWER COMPANY By ------------------------ Its --------------------- EMPLOYEE --------------------------- EXHIBIT A NOTICE The undersigned ("Employee") does hereby notify Otter Tail Power Company (the "Company") pursuant to Section 4(i) of that certain Severance Agreement dated as of the date hereof between the Company and Employee (the "Agreement") that Employee has elected to be paid any amounts which become payable under Section 4(i)(a) of the Agreement as follows: (check one) ______ in a lump sum not later than one business day prior to the date that the termination of Employee's employment becomes effective. ______ in 36 equal installments payable monthly, on the last business day of the month, for 36 consecutive months following the date that the termination of Employee's employment becomes effective. Dated: ------------------------- -------------------------------- Employee EX-13 7
EXHIBIT 13-A Selected consolidated financial data - ------------------------------------------------------------------------------------------------------------------------------ 1999 1998 (3) 1997 1996 1995 1994 1989 -------- ---------- -------- -------- -------- -------- -------- (thousands except per-share data) Revenues - -------- Electric $ 233,527 $ 227,477 $ 205,121 $ 199,345 $ 203,925 $ 198,812 $172,607 Manufacturing 93,411 87,434 83,174 64,568 38,690 13,083 - Health services 69,312 69,412 66,859 61,697 50,896 45,555 - Other business operations 68,327 48,829 44,173 45,323 32,818 29,276 1,756 --------- --------- --------- --------- --------- --------- -------- Total operating revenues $ 464,577 $ 433,152 $ 399,327 $ 370,933 $ 326,329 $ 286,726 $174,363 Special charges $ - $ 9,522 $ - $ - $ - $ - $ - Cumulative change in accounting principle $ - $ 3,819 $ - $ - $ - $ - $ - Net income (1) $ 44,977 $ 34,520 $ 32,346 $ 30,624 $ 28,945 $ 28,475 $ 25,266 Cash flow from operations $ 78,325 $ 63,959 $ 69,398 $ 68,611 $ 58,077 $ 51,832 $ 46,902 Total assets $ 680,788 $ 655,612 $ 655,441 $ 669,704 $ 609,196 $ 578,972 $462,596 Long-term debt $ 176,437 $ 181,046 $ 189,973 $ 163,176 $ 168,261 $ 162,196 $119,711 Redeemable preferred $ 18,000 $ 18,000 $ 18,000 $ 18,000 $ 18,000 $ 18,000 $ 14,815 Common shares outstanding (2) (4) (thousands) 23,850 23,759 23,462 23,072 22,360 22,360 23,589 Number of common shareholders (5) 13,438 13,699 13,753 13,829 13,933 14,115 14,277 Basic and diluted earnings per share (2) (6) $ 1.79 $ 1.36 $ 1.29 $ 1.23 $ 1.19 $ 1.17 $ 0.97 Dividends per common share (2) $ 0.99 $ 0.96 $ 0.93 $ 0.90 $ 0.88 $ 0.86 $ 0.76 - ------------------------------------------------------------------------------------------------------------------------------ Notes: (1) Includes net gain from sale of radio station assets of $8.1 million in 1999. (2) Common shares outstanding and per-share data reflect the effect of the two-for-one stock split effective March 15, 2000. (3) In the first quarter of 1998 the Company changed its method of electric revenue recognition in the states of Minnesota and South Dakota from meter-reading dates to energy-delivery dates. Basic and diluted earnings per share includes 16 cents per share related to the cumulative effect of the change in accounting principle. (4) Number of shares outstanding at year-end. (5) Holders of record at year-end. (6) Based on average number of shares outstanding.
Management's discussion and analysis of financial condition and results of operations (Per-share data reflects the effect of the stock split described in note 15 to the consolidated financial statements.) Management's major financial objective is to increase shareholder value by earning returns for shareholders that exceed returns available from comparable risk investments. Management can meet this objective by earning the returns regulators allow in electric operations combined with successfully growing diversified operations. Meeting this objective enables the Company to preserve and enhance its financial capability by maintaining optimal capitalization ratios and a strong interest coverage position, providing excellent returns to the common shareholder in the form of long-term capital appreciation and dividends, and preserving strong credit ratings on outstanding securities, which in the form of lower interest rates benefits both the Company's customers and shareholders. Liquidity: Liquidity is the ability to generate adequate amounts of cash to meet the Company's needs, both short-term and long-term. Historically, the Company's liquidity has been a function of its capital expenditures and debt service requirements, its net internal funds generation, and its access to long-term securities markets and credit facilities for external capital. Over the years the Company has achieved a high degree of long-term liquidity by maintaining desired capitalization ratios through timely stock and debt issuances or repurchases, maintaining strong bond ratings, implementing cost- containment programs, evaluating operations and projects on a cost-benefit approach, investing in projects that enhance shareholder value, and implementing sound tax-reduction strategies. Cash provided by operating activities of $78.3 million, as shown on the Consolidated Statement of Cash Flows for the year ended December 31, 1999, combined with cash provided by issuing $1.8 million in common stock and funds on hand of $3.9 million at December 31, 1998, allowed the Company to pay dividends, meet sinking fund payment requirements, acquire an additional company, redeem one series of preferred stock and finance its consolidated capital expenditures in 1999. The increase of $21 million in cash and cash equivalents primarily relates to the sale of the radio station assets that occurred during the fourth quarter. A significant amount of the cash on hand at December 31, 1999, was used to fund an acquisition in January 2000. In 1999 the Company issued 89,238 common shares under its Automatic Dividend Reinvestment and Share Purchase Plan, generating proceeds of $1.7 million. In June 1999 the Company began purchasing the common shares needed for this plan from the open market instead of issuing new shares. The Company estimates that funds internally generated net of forecasted dividend payments, combined with funds on hand, will be sufficient to meet sinking fund payments on First Mortgage Bonds and preferred stock redemption requirements in the next five years and to provide for its estimated 2000 through 2004 consolidated capital expenditures. Additional short-term or long-term financing will be required in the period 2000 through 2004 for the maturity of long-term debt, in the event the Company decides to refund or retire early any of its presently outstanding debt or cumulative preferred shares, or for other corporate purposes. Capital requirements: The Company's consolidated capital requirements include periodic and timely replacement of technically obsolete or worn-out equipment, new equipment purchases, and plant upgrades to accommodate anticipated growth. The electric segment has a construction and capital investment program to provide facilities necessary to meet forecasted customer demands and to provide reliable service. The construction program is subject to continuing review and is revised annually in light of changes in demands for energy, availability of energy within the power pool, cost of capacity charges relative to cost of new generation, environmental laws, regulatory changes, technology, the costs of labor, materials and equipment, and the Company's financial condition (including cash flow and earnings). Consolidated capital expenditures for the years 1999, 1998, and 1997 were $33 million, $29 million, and $42 million, respectively. The estimated capital expenditures for 2000 are $35 million, and the total capital expenditures for the five-year period 2000 through 2004 are expected to be approximately $210 million. The breakdown of 1999 actual and 2000 through 2004 estimated capital expenditures by segment is as follows: 1999 2000 2000-2004 ---- ---- --------- (in millions) Electric utility $ 20 $ 24 $125 Manufacturing 7 4 26 Health services 1 4 42 Other business operations 5 3 17 ---- ---- --------- Total $ 33 $ 35 $210 In addition to these capital requirements, funds totaling approximately $50 million will be needed during the five-year period 2000 through 2004 to retire First Mortgage Bonds and other long-term obligations at maturity (including sinking fund payments for First Mortgage Bonds and preferred stock redemption requirements). Capital resources: Financial flexibility is provided by unused lines of credit, strong financial coverages and credit ratings, and alternative financing arrangements such as leasing. As of December 31, 1999, the Company had $24.8 million in cash and cash equivalents and $32.7 million in lines of credit available. Bank lines of credit are a key source of operating capital and can provide interim financing of working capital and other capital requirements, if needed. The subsidiaries' notes and credit lines are secured by a pledge of all of the common stock of the subsidiaries. (See note 11 to consolidated financial statements.) The Company's coverage ratios improved in 1999 compared to 1998 due to the gain from the sale of radio station assets. The fixed charge coverage ratio after taxes was 6.1 for 1999 as compared to 4.0 for 1998, and the long-term debt interest coverage ratio before taxes was 6.1 for 1999, as compared to 4.3 for 1998. During 2000 the Company expects these coverages to return to ratios similar to 1998. The Company's credit ratings affect its access to the capital market. The current credit ratings for the Company's First Mortgage Bonds at December 31, 1999, which remain unchanged from 1998, are as follows: Moody's Investors Service Aa3 Duff and Phelps AA Standard and Poor's AA- The Company's disclosure of these security ratings is not a recommendation to buy, sell, or hold its securities. Results of operations: Electric operations Otter Tail Power Company provides electrical service to more than 126,000 customers in a service territory exceeding 50,000 square miles. 1999 1998 1997 -------- -------- -------- (in thousands) Operating revenues $233,527 $227,477 $205,121 Production fuel 36,839 34,234 31,362 Purchased power 44,190 40,609 24,420 Other operation and maintenance expenses 73,308 70,584 72,112 Special charges -- 7,022 -- Depreciation and amortization 21,782 22,128 21,442 Property taxes 10,174 10,684 10,819 -------- -------- -------- Operating income $ 47,234 $ 42,216 $ 44,966 (bar graph of information in following table) Electric operating income (millions) -------------------------------- 1997 $45.0 1998 $42.2 1999 $47.2 (end of graph) Electric operating revenues increased 2.7 percent in 1999, as compared to 1998, due to a $16.1 million increase in power pool revenues offset by a $5.5 million decrease in retail revenue and a $4.6 million decrease in other electric revenue. Hot summer weather in the Midwest and North Central regions of the United States, combined with increased emphasis on power marketing efforts and increased generation at the Company's plants contributed to the increase in power pool revenues. Reductions in kilowatt-hour (kwh) sales to industrial customers, particularly pipeline customers, combined with lower revenue per retail kwh for 1999 as compared to 1998 contributed to the decrease in retail revenues. The reduction in revenue per retail kwh primarily was due to a reduction in cost of energy revenues. Other electric revenue decreased $4.6 million primarily as a result of a reduction in electrical contract work done for other utilities combined with the Company's decision not to record 1999 Minnesota Conservation Improvement Program (CIP) financial incentives until approved by the Minnesota Public Utilities Commission (MPUC). See note 5 to consolidated financial statements. The 10.9 percent increase in electric operating revenues in 1998, as compared to 1997, is due to a $17.9 million increase in power pool revenues, combined with increases of $2.7 million in other electric revenue and $1.7 million in retail revenue. Power pool kwh sales increased 96 percent and revenue per power pool kwh sold increased 33 percent. An increase in energy available for sale enabled the Company to respond to unusually high wholesale market demands, resulting in the increase in power pool sales in 1998. The evolution of a competitive wholesale electricity market is reflected in market-based increases in revenue per power pool kwh sold and the cost per kwh of purchased power. Other electric revenue increased as a result of more electrical contract work done for other utilities and an increase in payments from other utilities for the use of shared transmission facilities. Retail revenue increased 0.9 percent despite a 0.3 percent decline in retail kwh sales. Revenue per retail kwh increased 1.2 percent in 1998, as compared to 1997, as a result of increases in the CIP surcharge rate and an increase in cost-of-energy revenues. Significantly milder weather during the first quarter of 1998 was the main contributing factor to the decline in retail kwh sales as heating degree days were down 18.7 percent for 1998 as compared to 1997. Increases or decreases in fuel and purchased power costs arising from changing prices results in adjustments to the Company's rate schedules through the cost of energy adjustment clause. During the last five years this has resulted in savings of more than $45 million to the Company's customers. Production fuel expense increased 7.6 percent in 1999 due to a 10.8 percent increase in kwh generated offset by a 2.5 percent decrease in the fuel cost per kwh generated at the Company's steam generating plants. The reduction in fuel cost per kwh generated is a result of a settlement with Knife River Coal Mining Company, which reduced the price of coal at Coyote Station. The 8.8 percent increase in purchased power expense in 1999 is directly related to a 43.6 percent increase in power pool kwh sales. The increase in power pool sales also drove the increase in kwhs generated at the Company's steam generating units. Greater plant availability in 1998, which allowed the Company to sell more wholesale power, resulted in a 9.1 percent increase in kwh generated and a 9.2 percent increase in production fuel expense in 1998 as compared to 1997. The 66.3 percent increase in purchased power costs in 1998 as compared to 1997 is due to a 161 percent increase in cost of power purchased for resale combined with a 6.8 percent increase in cost of power purchased for system use. The cost of power purchased for system use increased despite a 5.1 percent decrease in the volume of energy purchased for system use as a result of generally higher market prices for purchased power during 1998. Power purchased for resale increased due to a 96 percent increase in power pool sales combined with a 40 percent increase in cost per kwh purchased for resale. The 3.9 percent increase in other electric operation and maintenance expenses for 1999 as compared to 1998 primarily is due to the recording of expenses related to employee incentive programs and increased expenditures for transmission and distribution system line maintenance to enhance service reliability. These increases were offset by a reduction in material and supplies expenses due to less contracted work for other utilities during 1999 and no major overhaul work performed at the Company's generating plants in 1999. Other electric operation and maintenance expenses for 1998 as compared to 1997, decreased 2.1 percent. This decrease, in part, reflects the effect of the Company's early retirement program, which resulted in a workforce reduction of 55 employees by June 1, 1998. Maintenance expenses were higher in 1997 than in 1998 due to Coyote Station's ten-week overhaul in 1997. Special charges incurred in 1998 of $7 million represent two items related to electric operations: (1) a noncash charge of $6.3 million associated with the Company's voluntary early retirement program and (2) the write-off of $717,000 in accumulated costs related to a rail spur project at Big Stone Plant. (See note 3 to consolidated financial statements.) The Company incurred insignificant additional costs related to the early retirement offer after the first quarter of 1998. The 1.6 percent decrease in depreciation and amortization expense for 1999 as compared to 1998 is due to a decrease in depreciation rates offset by an increase in plant in service. Depreciation and amortization expense for 1998 as compared to 1997 increased 3.2 percent due to a slight increase in electric plant in service. Property taxes decreased 4.8 percent in 1999 as compared to 1998 due to reductions in Minnesota property taxes as a result of legislative action affecting commercial and industrial property class rates for 1999 and changes in the formula funding for schools. Manufacturing operations Manufacturing operations is made up of businesses involved in the production of polyvinyl chloride (PVC) pipe, agricultural equipment, frame-straightening equipment and accessories for the auto body shop industry, contract machining, and metal parts stamping and fabricating. 1999 1998 1997 -------- -------- -------- (in thousands) Operating revenues $93,411 $87,434 $83,174 Cost of goods sold 71,489 64,390 61,361 Operating expenses 14,698 13,435 12,668 -------- -------- -------- Operating income $ 7,224 $ 9,609 $ 9,145 (bar graph of information in following table) Manufacturing operating income (millions) ------------------------------- 1997 $9.1 1998 $9.6 1999 $7.2 (end of graph) The 6.8 percent increase in manufacturing operating revenue during 1999 as compared to 1998 was the result of increased sales of PVC pipe, stamped metal parts, and frame-straightening equipment offset by decreased revenues from manufacturing agricultural-related equipment. Manufacturing operating revenue increased 5.1 percent in 1998 as a result of increased sales volumes of 15 percent within the companies that produce agricultural equipment and stamp metal parts. These increases were offset by a reduction in sales of frame-straightening equipment and accessories for the auto body shop industry and a decrease in revenues from sales of PVC pipe. Cost of goods sold for the manufacturing operations increased 11.0 percent during 1999 due to the increase in sales volumes of PVC pipe and stamped metal parts combined with an increase in prices for resins used to manufacture PVC pipe. During 1998 manufacturing cost of goods sold increased 4.9 percent as a result of the increased sales volumes, offset by a decrease in prices for resins used to manufacture PVC pipe. Operating expenses increased 9.4 percent during 1999 as compared to 1998 primarily due to increases in sales expenses. The increase in operating expenses for 1998 of 6.1 percent was due primarily to increased labor costs and the use of outside professional services. Effective January 1, 2000, the Company acquired the assets and operations of Vinyltech Corporation, a manufacturer of PVC pipe located in Phoenix, Arizona. (See note 15 to consolidated financial statements.) Health services operations Health services operations include businesses involved in the sale, service, rental, refurbishing, and operation of medical imaging equipment and the sale of related supplies and accessories to various medical institutions. 1999 1998 1997 -------- -------- -------- (in thousands) Operating revenues $69,312 $69,412 $66,859 Cost of goods sold 55,464 53,473 53,191 Operating expenses 8,526 8,744 8,700 ------- ------- ------- Operating income $ 5,322 $ 7,195 $ 4,968 (bar graph of information in following table) Health services operating income (millions) -------------------------------- 1997 $5.0 1998 $7.2 1999 $5.3 (end of graph) Operating revenues for health services decreased slightly for 1999 as compared to 1998. Decreases in revenues from imaging scans performed were offset by increases in the sales of medical imaging equipment. The 3.8 percent increase in health services operating revenue in 1998, as compared to 1997, is due to an increase in sales volumes of diagnostic medical equipment combined with an increase in the number of medical imaging scans performed offset by a decrease in the average fee per scan. The decrease in operating revenues and the 3.7 percent increase in cost of goods sold during 1999 reflect the tightening of gross margins in this industry due to intense price competition. Operating expenses decreased 2.5 percent in 1999 due to an increased focus on reducing costs within the health services companies. Other business operations The Company's other business operations include businesses involved in electrical and telephone construction contracting, transportation, tele- communications, entertainment, energy services, and natural gas marketing. On September 1, 1999, the Company acquired the flatbed trucking operations of E. W. Wylie Corporation. (See note 4 to consolidated financial statements.) In October 1999 the Company completed the sale of certain assets of the radio stations and video production company owned by KFGO, Inc., and the radio stations owned by Western Minnesota Broadcasting Company for $24.1 million. Operating income includes results of operations for the radio stations through September 1999. The gain from this sale was not included in operating income for segment purposes. For additional information regarding the sale see note 4 to consolidated financial statements. During 1999 the Company agreed, as part of a settlement with the Minnesota Pollution Control Agency, to donate all of its assets in its Quadrant Co. waste incineration plant to the City of Perham, Minnesota. The plant had ceased operations during the third quarter of 1998, and a related impairment loss (shown as special charges in the table below) of $2.5 million was recorded in 1998. (See note 3 to consolidated financial statements.) Pro forma operating income for other business operations without Quadrant and the radio stations would have been $6,303,000, $1,543,000, and $3,953,000 in 1999, 1998, and 1997, respectively. Results of operations for the other business operations segment are as follows: 1999 1998 1997 -------- -------- -------- (in thousands) Operating revenues $68,327 $48,829 $44,173 Cost of goods sold 45,126 29,133 23,393 Special charges -- 2,500 -- Operating expenses 15,615 17,680 16,645 ------- ------- ------- Operating income (loss) $ 7,586 $ (484) $ 4,135 (bar graph of information in following table) Other business operations operating income (millions) ------------------------------------------ 1997 $ 4.1 1998 $(0.5) 1999 $ 7.6 (end of graph) The 39.9 percent increase in other business operations operating revenues in 1999 reflects an $8.5 million increase at the construction subsidiaries due to favorable construction markets and conditions, a $5.2 million increase at the natural gas marketing subsidiary reflecting a full year of operations, and inclusion of four months of operating revenues as a result of the Wylie acquisition. The 1999 operating revenues also increased as a result of the $1.5 million gain from the sale of an investment by the telecommunication subsidiary. Cost of goods sold increased 54.9 percent in 1999, as compared to 1998, due to a $6.5 million increase at the construction subsidiaries, a $4.7 million increase due to the full year of operations at the natural gas subsidiary, and inclusion of four months of expense as a result of the Wylie acquisition. Operating expenses decreased 11.7 percent as a result of the sale of the radio stations and the donation of the Quadrant plant. Other business operations operating revenues, cost of goods sold, and operating expenses increased 10.5 percent, 24.5 percent, and 6.2 percent, respectively, in 1998, as compared to 1997, primarily as a result of acquiring the natural gas marketing subsidiary. Gain from sale of radio station assets The Company recorded a $14.5 million pre-tax gain from the sale of certain assets of the six radio stations and the video production company owned by KFGO, Inc., and the two radio stations owned by Western Minnesota Broadcasting Company on October 1, 1999. The after-tax gain from this sale contributed $0.34 to earnings per share. Consolidated other income and deductions--net (bar graph of information in following table) Other income and deductions (millions) --------------------------- 1997 $2.0 1998 $2.9 1999 $1.8 (end of graph) Consolidated other income and deductions decreased 36.3 percent in 1999 due to decreases in financial incentives from demand-side management programs and dividend revenues offset by increased interest income. The 46.6 percent increase in other income and deductions for 1998, as compared to 1997 reflects an increase in dividend income combined with an increase in revenue recognition relating to Minnesota CIP financial incentives. Consolidated interest charges (bar graph of information in following table) Interest charges (millions) ---------------- 1997 $18.5 1998 $15.6 1999 $14.8 (end of graph) Interest charges for 1999 decreased 5.1 percent due to a reduction in average outstanding debt for the year and lower average interest rates. The 15.9 percent decrease in interest charges in 1998 as compared to 1997 is a result of a lower average interest rate on line of credit borrowings and of refinancing various diversified companies' fixed and variable interest rate debt with lower fixed rate debt in November 1997. In addition, the decrease can be attributed to the implementation of a consolidated cash management function within the subsidiaries that allowed excess cash to be used to reduce outstanding borrowings. Consolidated income taxes (bar graph of information in following table) Income taxes (millions) ------------ 1997 $14.3 1998 $15.1 1999 $23.9 (end of graph) The 58.0 percent increase in income taxes in 1999 as compared to 1998 reflects income tax expense of $6.4 million related to the sale of the radio station assets combined with an increase in income before tax. The 5.8 percent increase in income taxes in 1998 as compared to 1997 reflects the use of a capital loss carryforward in 1997 combined with an increase in income before tax for 1998. Cumulative effect of change in accounting principle In the first quarter of 1998 the Company changed its method of revenue recognition in Minnesota and South Dakota from meter-reading dates to energy- delivery dates resulting in the recognition of $6,364,000 ($3,819,000 net-of- tax or $0.16 per share) in unbilled revenues. (See note 2 to consolidated financial statements.) Impact of inflation The Company operates under regulatory provisions that allow price changes in the cost of fuel and purchased power to be passed to customers through automatic adjustments to its rate schedules under the cost of energy adjustment clause. Other increases in the cost of electric service must be recovered through timely filings for rate relief with the appropriate regulatory agency. The Company's health services, manufacturing, and other business operations consist almost entirely of unregulated businesses. Increased operating costs are reflected in product or services pricing with any limitations on price increases determined by the marketplace. The impact of inflation on these segments has been less significant during the past few years because of the relatively low rates of inflation experienced in the United States. Raw material costs, labor costs, and interest rates are important components of costs for companies in these segments. Any or all of these components could be impacted by inflation, with a possible adverse effect on the Company's profitability. Factors affecting future earnings The results of operations discussed above are not necessarily indicative of future earnings. Factors that might affect future earnings include, but are not limited to, the Company's ongoing involvement in diversification efforts, the timing and scope of deregulation and open competition, growth of electric revenues, changes in the economy of the Upper Midwest, governmental and regulatory action, fuel and purchase power costs and environmental issues. Anticipated higher operating costs and carrying charges on increased capital investment in plant, if not offset by proportionate increases in operating revenues and other income (either by appropriate rate increases, increases in unit sales, or increases in nonelectric operations), will affect future earnings. Diversification - --------------- In 1999 approximately 30 percent of the Company's net earnings were contributed by diversified operations, excluding the gain from the sale of the radio station assets. The Company plans to make additional acquisitions through its wholly owned subsidiary, Varistar Corporation. It is possible that by 2004, more than 45 percent of the Company's net earnings will be contributed from diversified operations. The following guidelines are used when considering acquisitions: emerging or middle market company; proven entrepreneurial management team that will remain after the acquisition; products and services that are intended for commercial rather than retail consumer use; the ability to provide immediate earnings and future growth potential; and 100 percent ownership. The Company intents to grow earnings as a long-term owner of these investments. However, such as in the case with the sale of the radio station assets during 1999, the Company will compare the returns of continued ownership of a business against its market value. Continuing revenue growth from diversified operations could result in earnings and stock price volatility. While we cannot predict the success of our current diversified businesses, we believe opportunities exist for growth in the business segments. Factors that could affect the results of the diversified businesses include, but are not limited to the following: fluctuations in the cost and availability of raw materials and the ability to maintain favorable supplier arrangements and relationships; competitive products and pricing pressures and the ability to gain or maintain market share in trade areas; effectiveness of advertising, marketing, and promotional programs; adverse weather conditions; and the highly competitive nature of the health services industry. Growth of electric revenue - -------------------------- Growth in electric sales will be subject to a number of factors, including the volume of power pool sales to other utilities, the effectiveness of demand-side management programs, weather, competition, and the rate of economic growth or decline in the Company's service area. The Company's electric business is primarily dependent upon the use of electricity by customers in our service area. The Company's electric kwh sales to retail customers decreased 2.6 percent and 0.3 percent in 1999 and 1998, respectively, and increased 1.4 percent in 1997. Factors beyond the Company's control, such as mergers and acquisitions, geographical location, transmission costs, unplanned interruptions at the Company's generating plants, and the effects of deregulation, could lead to greater volatility in the volume and price of power pool sales. Regulation - ---------- Rates of return earned on utility operations are subject to review by the various state commissions that have jurisdiction over the electric rates charged by the Company. These reviews may result in future revenue reductions when actual rates of return are deemed by regulators to be in excess of allowed rates of return. During 1999 the North Dakota Public Service Commission (NDPSC) approved a settlement agreement following an audit of the Company's electric operations in North Dakota. The effects of this settlement decreased 1999 earnings by approximately $441,000 after taxes or $0.02 per share. As part of the settlement the Company is required to refund to North Dakota customers any 1999 regulated electric operations earnings from North Dakota over a 12.5 percent return on equity and file with the NDPSC a proposal for performance- based ratemaking early in 2000. While the final decision on any potential refund relating to 1999 results lies with the NDPSC, the Company expects that any refund will not be significant. Load Management and Minnesota Conservation Improvement Programs - --------------------------------------------------------------- Load management efforts will continue in all jurisdictions served by the Company. The goal of load management is to control demand for electricity by customers at times of peak use in order to alleviate or delay the need for building or acquiring new generating capacity or to avoid having to purchase high-priced energy at times of peak demand. In addition to our load management efforts, we also invest in conservation improvement programs in Minnesota as mandated by state law. Conservation improvement programs are designed to encourage and reward the wise and efficient use of electricity by customers. In 1999, as a result of the Company's conservation improvement efforts, the MPUC approved the Company's 1998 financial incentive filing, including lost margins recovery, along with a 1.5 percent surcharge on all Minnesota customers' bills (approximately 0.75 percent of total retail revenue) from July 1, 1999 through June 30, 2000. The surcharge provides for the recovery of conservation-related costs and financial incentives in excess of those being recovered in current rates. The previous 12-month period surcharge was 2.75 percent. It is likely that any financial incentives approved by the MPUC in the future will result in a significantly lower surcharge because recent actions by the MPUC have indicated a movement toward the discontinuance of allowing recovery of lost margins. Fuel Costs - ---------- The Company has reached an agreement for Big Stone Plant's coal supply through December 31, 2001. In November 1995 the Company and two other Coyote Station owners initiated a lawsuit against Knife River Coal Mining Company and its parent, MDU Resources Group Inc., in an attempt to resolve disputes over pricing in the Coyote coal agreement. The case was remanded to arbitration in 1997. During 1999 settlement of the arbitration resulted in: (1) a reduction of fuel prices for Coyote Station, beginning March 26, 1999, (2) modification of the price adjustment provision of the contract for the future, and (3) a requirement that Knife River refund excess amounts paid for coal from September 13, 1996, through March 26, 1999. The Company received a refund of $2.7 million, representing its share as a co-owner of Coyote Station. This refund and accumulated interest has been recorded as a liability pending regulatory filing in each state to determine procedures for refunds to electric retail customers. The regulatory filings included a request to recover costs related to the arbitration incurred by the Company. The Mid-Continent Area Power Pool (MAPP) region has experienced a reduction in availability of excess generation and transmission capacity, particularly in the summer season in the past two years. While the availability of the Company's plants has been excellent, the loss of a major plant could expose the Company to higher purchased power costs. Two factors significantly mitigate this financial risk. First, wholesale sales contracts include provisions to release the Company from its obligations in case of a plant outage, and second, the Company has cost of energy adjustment clauses that allow pass through of energy costs to retail customers. Environmental - ------------- Current regulations under the Federal Clean Air Act (the Act) are not expected to have a significant impact on future capital requirements or operating costs. However, proposed or future regulations under the Act, changes in the future coal supply market, and/or other laws and regulations could impact such requirements or costs. It is anticipated that, under current regulatory principles, any such costs could be recovered through rates. The Company's electric generating plants were not subject to the Act's phase one requirements. Phase two standards of the Act must be met by the year 2000. The Company intends that Big Stone Plant will maintain current levels of operation and meet phase two requirements for sulfur dioxide emissions by burning subbituminous coal. The Company has a new coal contract that provides a lower sulfur subbituminous coal for Big Stone Plant. Under EPA regulations, modifications were required at Big Stone Plant by 2000 to satisfy nitrogen oxide emission standards. During 1997 the Company conducted tests at Big Stone Plant to determine if nitrogen oxide emissions could be reduced through modifications to existing equipment. The results of the tests were positive and modifications have been completed. The Company's Coyote Station is equipped with sulfur dioxide removal equipment. Compliance with the phase two requirements is not expected to significantly impact operations at that plant. Hoot Lake Plant already uses low-sulfur subbituminous coal, and minor modifications were completed to meet the phase two nitrogen oxide emission requirements. Deregulation and legislation - ---------------------------- In December 1999 the Federal Energy Regulatory Commission (FERC) issued Order No. 2000. This order requires public utilities that own, operate or control interstate transmission to file by October 15, 2000 a proposal for a regional transmission organization (RTO) or a description of any efforts made to participate in an RTO, the reasons for not participating, and any plans for further work towards participation. The goal is to consolidate control of the transmission industry into a new structure of independent, regional grid operators. In 1996 the Federal Energy Regulatory Commission (FERC) issued two final rules, Order Nos. 888 and 889, which give competing wholesale suppliers the ability to transmit electricity through a utility's transmission system. Order No. 888 requires electric utilities and other transmission providers to abide by, and to offer to other transmission users, terms, conditions and pricing comparable to those they use for themselves in transmitting power. Order No. 889, which became effective January 3, 1997, requires public utilities to implement Standards of Conduct and an Open Access Same-Time Information System (OASIS). These rules require transmission personnel to provide information about their transmission systems to all customers, including their marketing associates within their respective companies, through the OASIS. After rehearing, the FERC issued Orders 888A and B, further clarifying its intent to prevent any discriminatory abuse of market power by utilities controlling both transmission and generation assets. The Company filed its initial transmission tariff on July 9, 1996, as required by Order No. 888. A revised rate schedule became effective in the first quarter of 1997. The U.S. Congress ended its 1999 legislative session without taking action on proposed electric industry restructuring legislation. We expect that during 2000 Congress will continue to debate proposed legislation which, if enacted, would promote customer choice and a more competitive electric market. While the Company cannot predict the timing or what form the legislation might take, we continue to monitor the debate on the issues. The Minnesota Legislature did not take any significant legislative action on electric utility restructuring in 1999. However, the Minnesota Department of Commerce is drafting comprehensive retail access legislation that is planned to be introduced in January 2001. The Minnesota State Chamber of Commerce plans to introduce legislation in 2000 to separate costs for generation, transmission and distribution on electric service statements by July 1, 2001. Company personnel have participated in a number of working groups set up by the Minnesota Department of Commerce. In 1997 the North Dakota Legislature created a subcommittee to investigate the impact of electric utility industry restructuring on North Dakota. The North Dakota Legislature plans to deal first with tax issues surrounding restructuring pertaining to both investor- owned electric utilities and electric cooperatives. The South Dakota Legislature and Public Utility Commission continue to monitor the status of the industry restructuring and retail competition. The Company cannot predict the timing or impact of regulatory actions regarding restructuring. Competition in the electric industry - ------------------------------------ As the electric industry moves towards deregulation the Company expects the industry to become more competitive. The Company is taking a number of steps to position itself for success in a competitive marketplace. The Company has functionally unbundled its energy supply, energy delivery, and energy services operations. Necessary accounting systems have been developed to capture costs and determine the profitability of each of these business units and to identify areas for improvement and opportunities for increased profitability. Separate business plans have been created for each business unit. The Company has established an energy services business unit to promote the energy-related products and services traditionally offered to the Company's customers and to develop new products and services to be offered to current and potential customers in order to distinguish the Company from the competition. The Company offered a voluntary early retirement program in 1998 that reduced the electric utility staff by 55 employees. As the electric industry evolves and becomes more competitive, the Company believes it is well positioned to be successful. The Company's generation capacity appears poised for competition due to unit heat rate improvements and reductions in fuel and freight costs. A comparison of the Company's electric retail rates to the rates of other investor-owned utilities, cooperatives, and municipals in the states the Company serves indicates that its rates are competitive. In addition, the Company would attempt more flexible pricing strategies under an open, competitive environment. Year 2000 readiness disclosure - ------------------------------ During the last three years the Company worked on becoming year 2000 ready. The Company's readiness plan involved three phases: inventory, assessment and remediation/testing, all of which were completed prior to December 31, 1999. The Company coordinated its year 2000 efforts with those of MAPP and the North American Electric Reliability Council. Critical external parties were contacted, and contingency plans were developed. As of the date of this report the Company has not experienced or been notified of any significant year 2000 related issues or problems. While it still is possible that some issues have not surfaced yet, the Company believes that any such issues will not have a material adverse effect on the Company's consolidated results of operations. The costs of the Company's year 2000 readiness efforts have been funded with cash flows from operations. These costs were not substantially different from the normal, ongoing costs that are incurred for systems development, implementation, and maintenance due in part to the use of internal resources and the deferral of other projects. Management estimates that the total expenditures related to the Company's year 2000 readiness effort since 1997 were approximately $900,000. Accounting pronouncements In June 1999 the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 137 - Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133. This statement delays the effective date for SFAS 133 until periods beginning after June 15, 2000. SFAS 133 - Accounting for Derivative Instruments and Hedging Activities was issued by the FASB in June 1998. SFAS 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. The adoption of this statement is not expected to have a material impact on the Company's financial position as presently reported. Cautionary Statements In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, the Company makes the following statements. The information in this annual report includes forward-looking statements. Important risks and uncertainties that could cause actual results to differ materially from those discussed in such forward-looking statements are set forth above under "Factors affecting future earnings." Other risks and uncertainties may be presented from time to time in the Company's future Securities and Exchange Commission filings. Independent Auditors' Report To the Shareholders of Otter Tail Power Company: We have audited the accompanying consolidated balance sheets and statements of capitalization of Otter Tail Power Company and its subsidiaries (the Company) as of December 31, 1999, and 1998, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 1999. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1999, and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles. As discussed in note 2 to the consolidated financial statements, the Company changed its method of accounting for unbilled revenues in 1998. DELOITTE & TOUCHE LLP January 31, 2000 Minneapolis, Minnesota
Otter Tail Power Company - ------------------------ Consolidated Balance Sheets, December 31 1999 1998 - --------------------------------------------------------------------------------------------- (in thousands) Assets Plant Electric plant in service $ 779,037 $ 770,887 Diversified operations 99,558 89,094 --------- --------- Total 878,595 859,981 Less accumulated depreciation and amortization 386,618 370,290 --------- --------- Plant - net of accumulated depreciation and amortization 491,977 489,691 Construction work in progress 10,979 10,495 --------- --------- Net plant 502,956 500,186 --------- --------- Investments 19,502 20,612 --------- --------- Intangibles--net 23,311 21,176 --------- --------- Other assets 6,141 3,968 --------- --------- Current assets Cash and cash equivalents 24,762 3,919 Accounts receivable: Trade (less accumulated provision for uncollectible accounts: 1999, $832,000; 1998, $1,444,000) 40,685 41,249 Other 5,616 6,845 Materials and supplies: Fuel 3,808 3,418 Inventory, materials, and operating supplies 26,329 23,138 Deferred income taxes 3,123 2,730 Accrued utility revenues 9,923 11,179 Other 5,690 6,310 --------- --------- Total current assets 119,936 98,788 --------- --------- Deferred debits Unamortized debt expense and reacquisition premiums 3,251 3,737 Regulatory assets 4,111 3,774 Other 1,580 3,371 --------- --------- Total deferred debits 8,942 10,882 --------- --------- Total $ 680,788 $ 655,612 ========= ========= See accompanying notes to consolidated financial statements.
Otter Tail Power Company - ------------------------ Consolidated Balance Sheets, December 31 1999 1998 - ------------------------------------------------------------------------------------------------- (in thousands) Liabilities and Equity Capitalization (page 33) Common shares, par value $5 per share -- authorized, 50,000,000 shares; outstanding, 1999 -- 23,849,974 shares; 1998 -- 11,879,504 shares * $ 119,250 $ 59,398 Premium on common shares * - 39,919 Unearned compensation (301) - Retained earnings * 126,744 125,462 Accumulated other comprehensive income - 297 --------- -------- Total common equity 245,693 225,076 Cumulative preferred shares 33,500 38,831 Long-term debt: Electric utility 152,507 153,389 Diversified operations 23,930 27,657 --------- -------- Total capitalization 455,630 444,953 --------- -------- Current liabilities Short-term debt - 824 Sinking fund requirements and current maturities 5,948 5,794 Accounts payable 39,343 32,411 Accrued salaries and wages 6,197 3,946 Federal and state income taxes accrued 8,153 2,192 Other taxes accrued 10,818 11,119 Interest accrued 3,266 3,120 Other 3,589 3,826 --------- -------- Total current liabilities 77,314 63,232 --------- -------- Noncurrent liabilities 26,514 22,842 --------- -------- Commitments (note 8) - - --------- -------- Deferred credits Accumulated deferred income taxes 87,972 90,964 Accumulated deferred investment tax credit 16,295 17,481 Regulatory liabilities 11,359 11,692 Other 5,704 4,448 --------- -------- Total deferred credits 121,330 124,585 --------- -------- Total $ 680,788 $ 655,612 ========= ========= * 1999 amounts reflect the effect of stock split described in note 15. See accompanying notes to consolidated financial statements.
Otter Tail Power Company - ------------------------ Consolidated Statements of Income For the Years Ended December 31 1999 1998 1997 - -------------------------------------------------------------------------------------------------------------- (in thousands, except per-share amounts) Operating revenues Electric $ 233,527 $ 227,477 $ 205,121 Manufacturing 93,411 87,434 83,174 Health services 69,312 69,412 66,859 Other business operations 68,327 48,829 44,173 --------- --------- --------- Total operating revenues 464,577 433,152 399,327 Operating expenses Production fuel 36,839 34,234 31,362 Purchased power 44,190 40,609 24,420 Electric operation and maintenance expenses 73,308 70,584 72,112 Special charges - 9,522 - Cost of goods sold 172,079 146,996 137,945 Other nonelectric expenses 35,197 36,134 33,873 Depreciation and amortization 25,420 25,813 25,536 Property taxes 10,178 10,724 10,865 --------- --------- --------- Total operating expenses 397,211 374,616 336,113 Operating income Electric 47,234 42,216 44,966 Manufacturing 7,224 9,609 9,145 Health services 5,322 7,195 4,968 Other business operations 7,586 (484) 4,135 --------- --------- --------- 67,366 58,536 63,214 Gain from sale of radio station assets 14,469 - - Other income and deductions -- net 1,828 2,871 1,959 Interest charges 14,771 15,566 18,519 --------- --------- --------- Income before income taxes 68,892 45,841 46,654 Income taxes 23,915 15,140 14,308 --------- --------- --------- Income before cumulative effect of change in accounting principle 44,977 30,701 32,346 Cumulative effect of change in accounting principle (net-of-tax of $2,545) - 3,819 - --------- --------- --------- Net income 44,977 34,520 32,346 Preferred dividend requirements 2,228 2,358 2,358 --------- --------- --------- Earnings available for common shares $ 42,749 $ 32,162 $ 29,988 ========= ========= ========= Average number of common shares outstanding * 23,831 23,596 23,277 Basic and diluted earnings per share * Income before cumulative effect of change in accounting principle $1.79 $1.20 $1.29 Cumulative effect of change in accounting principle - 0.16 - --------- --------- --------- Basic and diluted earnings per share $1.79 $1.36 $1.29 Dividends per common share * $0.99 $0.96 $0.93 * Common shares outstanding and per-share data reflect the effect of the stock split described in note 15. See accompanying notes to consolidated financial statements.
Otter Tail Power Company - ------------------------ Consolidated Statements of Changes in Common Shareholders' Equity - ----------------------------------------------------------------------------------------------------------------------------------- Accumulated Common Par value, Premium on other shares common common Unearned Retained comprehensive Total outstanding shares shares compensation earnings income equity ------------ ----------------------------------------------------------- (in thousands, except common shares outstanding) Balance, December 31, 1996 11,536,056 $ 57,680 $ 29,885 $ - $107,864 $ 619 $196,048 Cash portion of Peoples pooling transaction, January 1, 1997 (209) (209) Common stock issuances 195,022 975 5,520 6,495 Comprehensive income: Net income 32,346 32,346 Unrealized gains on available-for-sale securities 103 103 Reversal of previously recorded unrealized gains on available-for-sale securities sold (359) (359) ------- Total comprehensive income 32,090 Cumulative preferred dividends at required annual rates (2,358) (2,358) Common dividends (21,496) (21,496) Distributions by pooled entities (414) (414) ------------ ----------------------------------------------------------- Balance, December 31, 1997 11,731,078 $ 58,655 $ 35,196 $ - $115,942 $ 363 $210,156 Common stock issuances 148,426 743 4,723 5,466 Comprehensive income: Net income 34,520 34,520 Unrealized loss on available-for-sale securities (66) (66) ------- Total comprehensive income 34,454 Cumulative preferred dividends at required annual rates (2,358) (2,358) Common dividends (22,642) (22,642) ------------ ----------------------------------------------------------- Balance, December 31, 1998 11,879,504 $ 59,398 $39,919 $ - $125,462 $ 297 $225,076 Common stock issuances 45,768 228 1,541 1,769 Common stock retired (285) (1) (1) (10) (12) Unearned compensation - stock options 301 (301) - Comprehensive income: Net income 44,977 44,977 Reversal of previously recorded unrealized gains on available-for-sale securities sold (297) (297) ------- Total comprehensive income 44,680 Cumulative preferred dividends at required annual rates (2,266) (2,266) Common dividends (23,554) (23,554) Two-for-one stock split - March 15, 2000 11,924,987 59,625 (41,760) (17,865) - ------------ ----------------------------------------------------------- Balance, December 31, 1999 23,849,974 $119,250 $ - $ (301) $126,744 $ - $245,693 See accompanying notes to consolidated financial statements.
Otter Tail Power Company - ------------------------ Consolidated Statements of Cash Flows For the Years Ended December 31 1999 1998 1997 - ----------------------------------------------------------------------------------------------------------------- (in thousands) Cash flows from operating activities Net income $44,977 $34,520 $ 32,346 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 34,796 34,965 39,302 Deferred investment tax credit--net (1,186) (1,186) (1,186) Deferred income taxes (3,816) (6,253) (3,155) Change in deferred debits and other assets (484) 99 1,204 Change in noncurrent liabilities and deferred credits 4,902 2,129 1,960 Allowance for equity (other) funds used during construction (246) (103) - Gain on sale of radio station assets (14,469) - - Loss/(Gain) on investments in and disposal of noncurrent assets 14 607 (1,722) Voluntary early retirement program charges - 6,305 - Cumulative effect of change in accounting principle - (3,819) - Asset impairment losses - 3,217 - Cash provided by (used for) current assets and current liabilities: Change in receivables, materials, and supplies (1,761) (5,765) (2,270) Change in other current assets 1,956 (2,962) 1,752 Change in payables and other current liabilities 7,536 2,804 908 Change in interest and income taxes payable 6,106 (599) 259 ------- ------- ------- Net cash provided by operating activities 78,325 63,959 69,398 ------- ------- ------- Cash flows from investing activities Gross capital expenditures (32,679) (29,289) (41,973) Proceeds from sale of radio station assets 24,063 - - Proceeds from disposal of noncurrent assets 1,930 3,359 20,802 Proceeds from the sales of marketable securities - - 785 Acquisitions--net of cash acquired (16,000) (1,372) - Change in other investments (9) (1,585) (470) ------- ------- ------- Net cash used in investing activities (22,695) (28,887) (20,856) ------- ------- ------- Cash flows from financing activities Change in short-term debt--net issuances (824) (1,276) (23,500) Proceeds from issuance of long-term debt 13,049 1,559 178,272 Proceeds from issuance of common stock 1,769 5,466 6,286 Payments for debt and common stock issuance expense - (82) (244) Payments for retirement of common stock (12) - - Redemption of preferred stock (5,331) - - Payments for retirement of long-term debt (17,618) (17,121) (181,917) Dividends paid (25,820) (25,000) (24,268) ------- ------- ------- Net cash used in financing activities (34,787) (36,454) (45,371) ------- ------- ------- Net change in cash and cash equivalents 20,843 (1,382) 3,171 Cash and cash equivalents at beginning of year 3,919 5,301 2,130 ------- ------- ------- Cash and cash equivalents at end of year $24,762 $ 3,919 $ 5,301 ======= ======= ======== Supplemental disclosures of cash flow information Cash paid during the year for: Interest (net of amount capitalized) $14,004 $15,189 $ 18,203 Income taxes $23,077 $22,966 $ 18,057 See accompanying notes to consolidated financial statements.
Otter Tail Power Company - ------------------------ Consolidated Statements of Capitalization, December 31 1999 1998 - ------------------------------------------------------------------------------------------- (in thousands) Total common shareholders' equity $ 245,693 $ 225,076 --------- --------- Cumulative preferred shares -- without par value (stated and liquidating value $100 a share) -- authorized 1,500,000 shares; outstanding: Series subject to mandatory redemption: $6.35, 180,000 shares; 9,000 shares due 2002-06; 135,000 shares due 2007 18,000 18,000 --------- --------- Other series: $3.60, 60,000 shares 6,000 6,000 $4.40, 25,000 shares 2,500 2,500 $4.65, 30,000 shares 3,000 3,000 $6.75, 40,000 shares 4,000 4,000 $9.00, 1999 - 0 shares; 1998 - 53,311 shares - 5,331 --------- --------- Total other preferred 15,500 20,831 --------- --------- Cumulative preference shares -- without par value, authorized 1,000,000 shares; outstanding: none Long-term debt First mortgage bond series: 7.25%, due August 1, 2002 18,600 18,800 8.75%, due September 15, 2021 18,400 18,600 8.25%, due August 1, 2022 27,900 28,200 Pollution control series: 6.40-6.80%, due February 1, 2006, Big Stone project 5,247 5,307 6.40-6.90%, due February 1, 2019, Coyote project 21,029 21,264 --------- --------- Total first mortgage bond series 91,176 92,171 Senior debentures 6.375%, due December 1, 2007 50,000 50,000 Industrial development refunding revenue bonds 5.00% due December 1, 2002 3,010 3,010 Pollution control refunding revenue bonds variable 5.50% at December 31, 1999, due December 1, 2012 10,400 10,400 Obligations of Varistar Corporation: 7.80% ten-year term note, due October 31, 2007 14,271 18,169 Various at 1.9% to 7.5% at December 31, 1999 13,521 14,281 Obligations of Otter Tail Energy Services Company 8.75% ten-year term note, due April 11, 2008 1,085 - Other 6 6 --------- --------- Total 183,469 188,037 Less: Current maturity 4,953 4,799 Sinking fund requirement 995 995 Unamortized debt discount and premium -- net 1,084 1,197 --------- --------- Total long-term debt 176,437 181,046 --------- --------- Total capitalization $ 455,630 $ 444,953 ========= ========= See accompanying notes to consolidated financial statements.
Otter Tail Power Company Notes to consolidated financial statements For the three years ended December 31, 1999 (All common share amounts and per-share data reflect the effect of the stock split described in note 15.) 1. Summary of accounting policies System of accounts--For regulatory reporting purposes, the electric utility's internal system of accounts are translated into the accounts of the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC), the Public Service Commission of North Dakota, and the Public Utilities Commissions of Minnesota and South Dakota. Principles of consolidation--The consolidated financial statements include the accounts of the Company and all wholly owned subsidiaries. Profits on sales between nonregulated affiliates and from the regulated electric utility company to nonregulated affiliates are eliminated. However, profits on sales to the regulated electric utility company from nonregulated affiliates are not eliminated, in accordance with the requirements of Statement of Financial Accounting Standards (SFAS) No. 71 - Accounting for the Effects of Certain Types of Regulation. Plant, retirements, and depreciation--Utility plant is stated at original cost. The cost of additions includes contracted work, direct labor and materials, allocable overheads, and allowance for funds used during construction. The cost of depreciable units of property retired plus removal costs less salvage is charged to the accumulated provision for depreciation. Maintenance, repairs, and replacement of minor items of property are charged to operating expenses. The provisions for utility depreciation for financial reporting purposes are made on the straight- line method based on the estimated service lives of the properties. Such provisions as a percent of the average balance of depreciable electric utility property were 3.06 percent in 1999, 3.12 percent in 1998, and 3.08 percent in 1997. Property and equipment of nonutility and diversified operations are carried at historical cost, or at the current appraised value if acquired in a business combination accounted for under the purchase method of accounting, and are depreciated on a straight-line basis over the useful lives (3 to 40 years) of the related assets. On sale or retirement of property and equipment, the cost and related accumulated depreciation are eliminated from the respective accounts and the resulting gain or loss is included in the consolidated financial statements. Jointly owned plants--The consolidated financial statements include the Company's 53.9 percent and 35 percent ownership interests in the assets, liabilities, revenue, and expenses of Big Stone Plant and Coyote Station, respectively. Amounts at December 31, 1999 and 1998 included in electric plant in service for Big Stone were $111,722,000 and $111,754,000, respectively, and the accumulated provision for depreciation and amortization was $66,734,000 and $63,635,000, respectively. Amounts at December 31, 1999 and 1998 included in electric plant in service for Coyote were $146,163,000 and $145,899,000, respectively, and the accumulated provision for depreciation and amortization was $67,289,000 and $63,463,000, respectively. The Company's share of direct revenue and expenses of the jointly owned plants in service is included in the corresponding operating revenue and expenses in the statement of income. Allowance for funds used during construction (AFC)--AFC, a noncash item, is included in construction work in progress. The rate for AFC was 10.00 percent for 1999, 10.25 percent for 1998, and 5.67 percent for 1997. Recoverability of long-lived assets--The Company reviews its long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. The Company determines potential impairment by comparing the carrying value of the assets with net cash flows expected to be provided by operating activities of the business or related assets. Should the sum of the expected future net cash flows be less than the carrying values, the Company would determine whether an impairment loss should be recognized. An impairment loss would be quantified by comparing the amount by which the carrying value exceeds the fair value of the asset where fair value is based on the discounted cash flows expected to be generated by the asset. Income taxes--Comprehensive interperiod income tax allocation is used for substantially all book and tax temporary differences. Deferred income taxes arise for all temporary differences between the book and tax basis of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect when the temporary differences reverse. The Company amortizes the investment tax credit over the estimated lives of the related property. Operating revenues--Electric customers' meters are read and bills are rendered on a cycle basis. In the first quarter of 1998, the Company changed its method of revenue recognition in the states of Minnesota and South Dakota from meter-reading dates to energy-delivery dates, resulting in the accrual of estimated unbilled revenue from sales of electricity through the end of the accounting period. This change is consistent with the way the Company has been recording electric revenue from its North Dakota customers since 1993 under an order from the North Dakota Public Service Commission. See note 2 for the cumulative effect of recording Minnesota and South Dakota unbilled revenue as of January 1, 1998. The Company's rate schedules applicable to substantially all customers include a cost of energy adjustment clause under which the rates are adjusted to reflect changes in average cost of fuels and purchased power and a surcharge for recovery of conservation-related expenses. (See further discussion under note 5.) Health services' operating revenues on major equipment and installation contracts are recorded using the percentage-of-completion method. Amounts received in advance under customer service contracts are deferred and recognized on a straight-line basis over the contract period. Revenues generated in the mobile imaging operations are recorded on a fee for scan basis. Manufacturing operating revenues are recorded when products are shipped, when services are rendered, and on a percentage-of-completion basis for construction type contracts. Other business operations' operating revenues are recorded when services are rendered or products are shipped. In the case of construction contracts, the percentage-of-completion method is used. Employee incentive plan--The Company has incentive plans covering employees that are based on certain performance measures. Total amounts of accrued compensation for these incentive plans in 1999, 1998, and 1997 were $5,671,000, $3,083,000, and $3,826,000, respectively. Stock-based compensation--As described in note 6, the Company has elected to follow the accounting provisions of Accounting Principle Board Opinion No. 25 (APB 25), Accounting for Stock Issued to Employees, for stock- based compensation and to furnish the pro forma disclosures required under SFAS No. 123, Accounting for Stock-Based Compensation. Use of estimates--In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as depreciable lives, tax provisions, collectability of trade accounts receivable, workers' compensation claims, self insurance programs, injuries and damages reserve, environmental liabilities, unbilled revenues, service contract maintenance costs and actuarially determined benefit costs. As better information becomes available (or actual amounts are determinable) the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Reclassifications--Certain prior year amounts have been reclassified to conform to 1999 presentation. Such reclassification had no impact on net income and shareholders' equity. In addition, all financial information pertaining to per-share amounts and number of common shares outstanding has been adjusted to reflect a two-for-one stock split effective March 15, 2000, for shareholders of record on February 15, 2000. Cash equivalents--The Company considers all highly liquid debt instruments purchased with a maturity of 90 days or less to be cash equivalents. Debt reacquisition premiums--In accordance with regulatory treatment, the Company defers utility debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. Investments--At December 31, 1999 and 1998, the Company had noncurrent investments of $7,219,000 and $7,540,000, respectively, in limited partnerships that invest in tax-credit qualifying affordable housing projects. These investments, accounted for under the equity method, provided the Company with tax credits of $1,393,000 and $1,330,000, in 1999 and 1998, respectively. At December 31, 1999 the Company did not have any investments in marketable equity securities classified as available-for-sale. At December 31, 1998, the Company had $590,000 invested in marketable equity securities classified as available- for-sale and recorded at market value. The balance of investments at December 31, 1999 consists of $2,013,000 in additional investments accounted for under the equity method, and $10,270,000 in other investments accounted for under the cost method, with $1,424,000 related to participation in economic development loan pools. The balance of investments at December 31, 1998 consists of $1,911,000 in additional investments accounted for under the equity method, and $10,571,000 in other investments accounted for under the cost method, with $1,515,000 related to participation in economic development loan pools. (See further discussion under note 12.) Inventories--The electric operation inventories are reported at average cost. The health service, manufacturing, and other business operation inventories are stated at the lower of cost (first-in, first-out) or market. Short-term debt--There was no short-term debt outstanding as of December 31, 1999. The composite interest rate on short-term debt outstanding as of December 31, 1998, was 8.75 percent. The average interest rate paid on short-term debt during 1999 and 1998 was 8.75 percent and 6.65 percent, respectively. Intangible assets--The majority of the Company's intangible assets consist of goodwill associated with the acquisition of subsidiaries. Intangible assets are amortized on a straight-line basis over periods of 40 years for the telephone company and 15 years or less for all other intangibles. The Company periodically evaluates the recovery of intangible assets based on an analysis of undiscounted future cash flows. Total intangibles as of December 31 are as follows: 1999 1998 -------- -------- (in thousands) Goodwill on telephone company $ 7,749 $ 7,749 Other intangible assets 23,428 21,808 ------- ------- Total 31,177 29,557 Less accumulated amortization 7,866 8,381 ------- ------- Intangibles-net $23,311 $21,176 ======= ======= Adoption of new accounting pronouncements--In 1998 the Company adopted Statement of Financial Accounting Standards (SFAS) 131 - Disclosures about Segments of an Enterprise and Related Information. SFAS 131 supersedes SFAS 14, Financial Reporting for Segments of a Business Enterprise, replacing the "industry segment" approach with the "management" approach. The management approach designates the internal organization that is used by management for making operating decisions and assessing performance as the source of the Company's reportable segments. SFAS 131 also requires disclosures about products and services, geographic areas, and major customers. The adoption of SFAS 131 did not change the Company's reportable segments or affect results of operations or financial position. In February 1998 the Financial Accounting Standards Board (FASB) issued SFAS 132 - Employers' Disclosures about Pensions and Other Postretirement Benefits, which was effective for the Company on January 1, 1998. SFAS 132 revises employers' disclosures about pension and other postretirement benefit plans. The adoption of SFAS 132 did not affect the Company's 1998 results of operations or financial position. Note 10 reflects the adoption of SFAS 132. New accounting pronouncement--In June 1998 the FASB issued Statement of Financial Accounting Standards (SFAS) 133 - Accounting for Derivative Instruments and Hedging Activities, effective for financial statements issued for periods beginning after June 15, 1999. In June 1999 the FASB issued SFAS 137 which delayed the effective date for SFAS 133 to periods beginning after June 15, 2000. SFAS 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires that all derivatives be recognized as either assets or liabilities and that those financial instruments be measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative. The adoption of this statement is not expected to have a material impact on the Company's financial position as presently reported. 2. Change in accounting principle Effective January 1, 1998 the Company changed its method of revenue recognition in the states of Minnesota and South Dakota from meter- reading dates to energy-delivery dates, resulting in the accrual of estimated unbilled revenue from sales of electricity through the end of the accounting period. This change is consistent with the way the Company has been recording electric revenue from its North Dakota customers since 1993 under an order from the North Dakota Public Service Commission. The cumulative effect of recording Minnesota and South Dakota unbilled revenue as of January 1, 1998, increased 1998 net income by $3,819,000 (net of income taxes of $2,545,000) or $0.16 per share. The effect on 1998 income of this accounting change, not including the cumulative effect, was an increase in net income of approximately $193,000 or $0.01 per share. If the Company had been recording Minnesota and South Dakota unbilled revenue in previous accounting periods, its reported electric revenue for 1997 would have been $203,778,000 and its reported net income would have been $31,540,000 or $1.25 per share for 1997. 3. Special charges In January 1998 the Company offered a voluntary early retirement program for all nonunion electric utility employees age 55 and over. Most of the cash costs of the program will be funded through the Company's pension plan. The Company recorded a noncash charge to operating expenses of $6,305,000 ($3,783,000 net-of-tax or $0.16 per share) in 1998 for special termination benefits and the recognition of previously unrecognized prior service costs related to pension and postretirement benefits. In March 1998 the Company recorded a noncash accounting charge related to the impairment of its Quadrant Co. (Quadrant) waste incineration plant. The impaired assets include buildings, machinery, and equipment used to burn waste. The revised carrying value of this group of assets was determined to be zero, which was calculated on the basis of discounted estimated future cash flows. The pre-tax noncash charge of $2,500,000 ($1,500,000 net-of-tax or $0.06 per share) pertaining to the write down included $248,000 for selling or disposal costs all of which was used toward the disposition of the plant. The recognition of this impairment is in accordance with the provisions of Statement of Financial Accounting Standards No. 121 - Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to Be Disposed Of. The $2,500,000 impairment loss was included in operating expenses under the caption of special charges and in operating income from other business operations on the Company's Statement of Income for the year ended December 31, 1998. In August 1999 the assets of the Quadrant plant were donated to the City of Perham, Minnesota. In the first quarter of 1998, as a result of an unfavorable court decision related to the construction of a rail spur intended to serve Big Stone Plant, the Company wrote off $717,000 ($430,000 net-of-tax or $0.02 per share) in capitalized project related costs. 4. Business combinations, dispositions and segment information As discussed in note 3 above, during August 1999, the assets of the Quadrant plant were donated to the City of Perham, Minnesota. On September 1, 1999 the Company acquired the flatbed trucking operations of E. W. Wylie Corporation (Wylie). Wylie's annual revenues range from $18 to $19 million. The acquisition was accounted for using the purchase method of accounting. The excess of the purchase price over net assets acquired of approximately $8 million is being amortized over 15 years. Wylie is located in Fargo, North Dakota and operates in 48 states and 6 Canadian provinces. The pro forma effect of the Wylie acquisition on 1999, 1998 and 1997 revenue, net income, or earnings per share was not significant. On October 1, 1999 the Company completed the sale of certain assets of the radio stations and video production company owned by KFGO, Inc. and the radio stations owned by Western Minnesota Broadcasting Company for $24.1 million. The gain after income tax was $8.1 million or $0.34 cents per share. Pro forma operating income for other business operations without Quadrant and the radio stations would have been $6,303,000 $1,543,000 and $3,953,000 in 1999, 1998, and 1997 respectively. On May 1, 1998 the Company acquired PAM Natural Gas, Inc. (PAM) for approximately $1.8 million in stock purchased on the open market. PAM is a Sioux Falls, South Dakota-based marketer of natural gas to commercial and institutional customers in Iowa, South Dakota, North Dakota and Minnesota. Upon acquisition PAM's name was changed to Otter Tail Energy Management Company. The PAM acquisition was accounted for under the purchase method. The pro forma effect of the PAM acquisition on 1998 and 1997 revenue, net income, or earnings per share was not significant. Effective November 1998 Mid-States Development, Inc., a subsidiary of the Company since 1989, changed its name to Varistar Corporation (Varistar). On January 1, 1999 the Company's telecommunications subsidiary, North Central Utilities, Inc. (NCU) merged with Varistar. Subsidiaries previously owned by NCU became wholly owned subsidiaries of Varistar. Segment information--The accounting policies of the segments are the same as those described in the note 1 - Summary of accounting policies. The Company's business operations are broken down into four segments based on products and services. Electric operations includes the electric utility only and is based in Minnesota, North Dakota, and South Dakota. Manufacturing operations is made up of businesses involved in the production of polyvinyl chloride pipe, agricultural equipment, frame- straightening equipment and accessories for the auto body shop industry, contract machining, and metal parts stamping and fabrication located primarily in the Upper Midwest. Health services operations consists of businesses involved in the sale, service, rental, refurbishing and operations of medical imaging equipment and the sale of related supplies and accessories to various medical institutions located in 23 states. Other business operations consists of businesses diversified in such areas as electrical and telephone construction contracting, transporta- tion, telecommunications, entertainment, and energy services and natural gas marketing. The electrical and telephone construction contracting companies, and energy services and natural gas marketing business operate primarily in the Upper Midwest. The telecommunications companies operate in central and northeast Minnesota and the transportation company operates in 48 states and 6 Canadian provinces. The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on investment. Information for the business segments for 1999, 1998 and 1997 is presented in the table below. 1999 1998 1997 -------- -------- -------- (in thousands) Operating revenue Electric $233,527 $227,477 $205,121 Manufacturing 93,411 87,434 83,174 Health services 69,312 69,412 66,859 Other business operations 68,327 48,829 44,173 -------- -------- -------- Total $464,577 $433,152 $399,327 Operating income Electric $ 47,234 $ 42,216 $ 44,966 Manufacturing 7,224 9,609 9,145 Health services 5,322 7,195 4,968 Other business operations 7,586 (484) 4,135 -------- -------- -------- Total $ 67,366 $ 58,536 $ 63,214 Depreciation and amortization Electric $ 21,782 $ 22,128 $ 21,442 Manufacturing 562 510 542 Health services 499 541 638 Other business operations 2,577 2,634 2,914 -------- -------- -------- Total $ 25,420 $ 25,813 $ 25,536 Capital expenditures Electric $ 20,136 $ 17,939 $ 26,603 Manufacturing 6,903 5,536 6,264 Health services 993 3,101 3,800 Other business operations 4,647 2,713 5,306 -------- -------- -------- Total $ 32,679 $ 29,289 $ 41,973 Identifiable assets Electric $524,012 $525,226 $526,679 Manufacturing 46,832 41,579 40,814 Health services 29,542 36,241 35,738 Other business operations 80,402 52,566 52,210 -------- -------- -------- Total $680,788 $655,612 $655,441 No single external customer accounts for 10 percent or more of the Company's revenues. Substantially all sales and long-lived assets of the Company are within the United States. 5. Rate matters On October 6, 1999, the NDPSC approved a settlement agreement following an audit of the Company's electric operations in North Dakota. The effect of this settlement decreased 1999 earnings by approximately $441,000 after taxes or $0.02 per share. In addition as part of the settlement agreement, the Company filed a proposal for a performance- based ratemaking plan in 2000 and is required to refund to North Dakota customers any 1999 regulated electric operations earnings from North Dakota over a 12.5% return on equity. While the final decision on any potential refund relating to 1999 results lies with the NDPSC, the Company expects that any refund will not be significant. On July 1, 1995, the Company began charging all Minnesota customers a .5030 percent surcharge on their electric service statements for recovery of conservation-related costs exceeding the amount already included in base rates. On July 1, 1996, the rate was increased to 1.25 percent, on July 1, 1997, the rate was increased to 1.75 percent, on July 1, 1998, the rate was increased to 2.75 percent and on July 1, 1999, the rate was decreased to 1.5 percent. The conservation-related costs being recovered through the surcharge and in base rates include Conservation Improvement Program (CIP) expenditures, carrying charges on costs incurred in excess of costs currently being recovered, lost margins on avoided kilowatt-hour sales, and bonus incentives related to energy savings. The MPUC approved recovery of 1998, 1997, and 1996 lost margins and bonus incentives in 1999, 1998, and 1997, respectively. The Company recorded revenues related to 1998, 1997, and 1996 lost margins and financial incentives of $1,829,000, $1,931,000, and $1,266,000, respectively. As these costs are recovered through the monthly billing process, the amounts billed are offset by the amortization of deferred CIP charges. The Company did not record any estimated financial incentives for 1999. 6. Common shares Stock incentive plan--During 1999, the Company's shareholders approved the 1999 Stock Incentive Plan (Incentive Plan). Under the Incentive Plan a total of 2,600,000 common shares are available for granting of stock awards. The Incentive Plan provides for the grant of options, performance awards, restricted stock, stock appreciation rights and other types of stock grants or stock-based awards. In 1999, the Company granted approximately 450,700 stock options and 2,298 shares of restricted stock under the Incentive Plan. The exercise price of the stock options is equal to the fair market value per share at the date of the grant. The options vest over a four-year period at the rate of 25 percent per year and will expire ten years after the date of the grant. Presented below is a summary of the stock options activity for 1999. No stock options were granted prior to 1999. Balance, December 31, 1998 -- Granted 450,700 Forfeited (7,800) ------- Balance, December 31, 1999 442,900 The Company accounts for the Incentive Plan under APB 25. Unearned compensation relating to the options granted in 1999 is $301,000 at December 31, 1999, and is included as a reduction of common equity. Since none of the options had vested as of December 31, 1999, no compensation expense occurred under SFAS No. 123 and there was no impact on the Company's net income and earnings per share. The fair value of each option grant is estimated on the date of grant using the Black Scholes option pricing model with the following weighted-average assumptions used to the grant Risk free interest rate 5.2% Expected dividend yield 5.0% Expected life 7 years Expected volatility 19.29% Weighted average fair value $2.79 The effect of the stock options on the computation of diluted earnings per share was immaterial for 1999. Employee stock purchase plan--During 1999, the shareholders approved the Company's 1999 Employee Stock Purchase Plan (Purchase Plan). The Purchase Plan allows eligible employees to purchase the Company's common shares at 85 percent of the lower market price at either the beginning or the end of each six-month purchase period. A total of 400,000 common shares is available for purchase by employees under the Purchase Plan. For 1999 there was only one purchase period that was in effect from May 1 through December 31, 1999. During January 2000, 24,080 shares were purchased from the open market for the Purchase Plan. The purchase price per share paid by the employees was $15.96. The average price paid by the Company to purchase these shares was $19.36. Dividend reinvestment and share purchase plan--On August 30, 1996, the Company filed a shelf registration statement with the Securities and Exchange Commission for the issuance of up to 2,000,000 common shares pursuant to the Company's Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by shareholders, or customers who participate in the Plan to be either new issue common shares or common shares purchased on the open market. In June 1999, the Company began purchasing the common shares needed for this Plan from the open market instead of issuing new shares. Prior to this the Company had been issuing newly issued common shares: 89,238 shares were issued in 1999, 296,852 shares were issued in 1998, and 323,662 shares were issued in 1997. Shareholder rights plan--On January 27, 1997, the Company's Board of Directors declared a dividend of one preferred share purchase right (Right) for each outstanding common share held of record as of February 10, 1997. One Right was also issued with respect to each common share issued after February 10, 1997. Each Right entitles the holder to purchase from the Company one one-hundredth of a share of newly created Series A Junior Participating Preferred Stock at a price of $70, subject to certain adjustment. The Rights are exercisable when, and are not transferable apart from the Company's common shares until, a person or group has acquired 15 percent or more, or commenced a tender or exchange offer for 15 percent or more, of the Company's common shares. If the specified percentage of the Company's common shares is acquired, each Right will entitle the holder (other than the acquiring person or group) to receive, upon exercise, common shares of either the Company or the acquiring company having value equal to two times the exercise price of the Right. The Rights are redeemable by the Company's Board of Directors in certain circumstances and expire on January 27, 2007. 7. Retained earnings restriction The Company's Indenture of Mortgage and Articles of Incorporation, as amended, contain provisions that limit the amount of dividends that may be paid to common shareholders. Under the most restrictive of these provisions, retained earnings at December 31, 1999, were restricted by $9,667,000. 8. Commitments At December 31, 1999, the electric utility had commitments under contracts in connection with construction programs aggregating approximately $4,211,000. For capacity and energy requirements the electric utility has agreements extending through 2004, at annual costs of approximately $10,977,000 in 2000, $12,591,000 in 2001, $12,791,000 in 2002, $11,197,000 in 2003, and $11,411,000 in 2004. The electric utility also has several long-term coal contracts in which it is responsible for making payment only upon the delivery of the coal. The risk of loss from nonperformance of the contracts is considered nominal because of the availability of other suppliers and the expected continued reliability of the current fuel suppliers. Furthermore, the cost of energy adjustment provision in the rate-making process lessens the risk of loss (in the form of increased costs) from market price changes because it assures recovery of almost all fuel costs. In 1999, the Company entered into a 5-year operating lease for 120 used hopper rail cars for transporting coal to the Hoot Lake Plant. These cars began transporting coal to the Hoot Lake Plant in July 1999. In November 1997 Varistar's medical imaging services subsidiary entered into a sale/leaseback transaction whereby $16,000,000 of diagnostic medical equipment was sold and leased back under two operating leases with terms of three and four years. The amounts of future operating lease payments are as follows: Electric Diversified utility companies Total -------- ----------- ------- (in thousands) 2000 $1,362 $12,106 $13,468 2001 1,299 10,242 11,541 2002 1,299 6,333 7,632 2003 1,299 3,507 4,806 2004 1,072 175 1,247 Later years 2,885 -- 2,885 Rent expense was $14,233,000, $13,016,000, and $6,714,000 for 1999, 1998, and 1997, respectively. 9. Long-term obligations Preferred shares--The $6.35 cumulative preferred shares are redeemable in whole or in part at the option of the Company after December 1, 1999, at $101.905, declining linearly to $100.00 at December 31, 2002. The aggregate requirement of cumulative preferred shares subject to mandatory redemption outstanding at December 31, 1999 for the next five years is $900,000 each year for 2002-2004. During 1999, the Company redeemed all of its outstanding $9.00 exchangeable cumulative preferred stock at par in an exchange for 227,952 shares of common stock, purchased on the open market, and $547,000 in cash. Long-term debt--All utility property, with certain minor exceptions, is subject to the lien of the Indenture of Mortgage of the Company securing its First Mortgage Bonds. The Company is required by the Indenture to make annual payments (exclusive of redemption premiums) for sinking fund purposes, except that the requirement with respect to certain series may be satisfied by the delivery of bonds of such series of equal principal amount. The Company issued First Mortgage Bonds of its pollution control series to secure payment of a like principal amount of revenue bonds that were issued by local governmental units to finance facilities leased or purchased and that the Company has capitalized. Varistar's ten-year term note and credit line borrowings are secured by a pledge of all of the common stock of the companies owned by Varistar. The aggregate amounts of maturities and sinking fund requirements on bonds outstanding and other long-term obligations at December 31, 1999, for each of the next five years are $5,947,000 for 2000, $5,611,000 for 2001, $26,231,000 for 2002, $4,700,000 for 2003, and $4,697,000 for 2004. 10. Pension plan and other postretirement benefits The utility company's noncontributory funded pension plan covers substantially all electric utility employees. The plan provides 100 percent vesting after 5 vesting years of service and for retirement compensation at age 65, with reduced compensation in cases of retirement prior to age 62. The utility company reserves the right to discontinue the plan, but no change or discontinuance may affect the pensions theretofore vested. The utility company's policy is to fund pension costs accrued. All past service costs have been provided for. The pension plan has a trustee who is responsible for pension payments to retirees. Five investment managers are responsible for managing the plan's assets. In addition, an independent actuary performs the necessary actuarial valuations for the plan. Net periodic pension cost for 1999, 1998, and 1997 includes the following components: 1999 1998 1997 -------- -------- -------- (in thousands) Service cost--benefit earned during the period $ 3,080 $ 2,319 $ 2,385 Interest cost on projected benefit obligation 8,150 7,823 7,131 Expected return on assets (12,159) (10,988) (9,036) Amortization of transition asset (235) (235) (235) Amortization of prior-service cost 1,287 1,069 980 Amortization of net gain (149) (344) (121) ------ ------ ------ Net periodic pension cost $ (26) $ (356) $1,104 1998 early retirement and curtailment -- 4,026 -- ------ ------ ------ Total $ (26) $3,670 $1,104 ====== ====== ====== The plan assets consist of common stock and bonds of public companies, U.S. Government Securities, cash, and cash equivalents. The following tables provide a reconciliation of the changes in the plan's benefit obligations and fair value of assets over the two-year period ending December 31, 1999 and a statement of the funded status as of December 31 of both years: 1999 1998 -------- -------- (in thousands) Reconciliation of benefit obligation: Obligation at January 1 $128,505 $107,357 Service cost 3,080 2,319 Interest cost 8,150 7,823 Actuarial (gain)/loss (18,025) 13,924 Benefit payments (7,265) (6,813) 1998 early retirement and curtailment -- 3,895 -------- -------- Obligation at December 31 $114,445 $128,505 ======== ======== Reconciliation of fair value of plan assets: Fair value of plan assets at January 1 $150,026 $137,560 Actual return on plan assets 16,613 19,054 Pension purchase options rollovers 181 225 Benefit payments (7,265) (6,813) -------- -------- Fair value of plan assets at December 31 $159,555 $150,026 ======== ======== Funded status: Funded status at December 31 $ 45,110 $ 21,521 Unrecognized transition asset (545) (780) Unrecognized prior-service cost 11,461 9,393 Unrecognized net actuarial gain (57,040) (31,174) -------- -------- Net amount recognized $ (1,014) $ (1,040) ======== ======== The following table provides the amounts recognized in the statement of financial position as of December 31 of both years: 1999 1998 -------- -------- (in thousands) Accrued benefit liability $ (1,014) $ (1,040) The assumptions used for actuarial valuations were: 1999 1998 -------- -------- Discount rate 7.75% 6.50% Rate of increase in future compensation level 4.25% 4.25% Long-term rate of return on assets 9.50% 9.50% In addition to providing pension benefits to all electric utility employees, the Company has an unfunded, nonqualified benefit plan for executive officers and certain key management employees. This plan provides defined benefit payments to these employees on their retirements or to their beneficiaries on their death for a 15-year period. Life insurance carried on the plan participants is payable to the Company upon the employee's death. There are no plan assets in this nonqualified benefit plan due to the nature of the plan. Net periodic pension cost for 1999, 1998, and 1997 includes the following components: 1999 1998 1997 -------- -------- -------- (in thousands) Service cost--benefit earned during the period $ (99) $ (88) $ (140) Interest cost on projected benefit obligation 569 521 475 Amortization of transition obligation 17 18 20 Amortization of prior service cost 106 111 127 Recognized net actuarial loss 47 --- --- ------ ------ ------ Net periodic pension cost $ 640 $ 562 $ 482 1998 early retirement and curtailment -- 1,413 -- ------ ------ ------ Total $ 640 $1,975 $ 482 ====== ====== ====== The following tables provide a reconciliation of the changes in the plan's benefit obligations over the two-year period ending December 31, 1999 and a statement of the funded status as of December 31 of both years: 1999 1998 -------- -------- (in thousands) Reconciliation of benefit obligation: Obligation at January 1 $ 9,071 $ 6,964 Service cost (99) (88) Interest cost 569 521 Plan amendments 1,618 -- Actuarial (gain)/loss (318) 807 Benefit payments (429) (273) 1998 early retirement and curtailment -- 1,140 -------- -------- Obligation at December 31 $ 10,412 $ 9,071 ======== ======== Funded status: Funded status at December 31 $ (10,412) $ (9,071) Unrecognized transition obligation 17 34 Unrecognized prior-service cost 2,785 1,273 Unrecognized net actuarial loss 1,057 1,422 -------- -------- Net amount recognized $ (6,553) $ (6,342) ======== ======== The following table provides the amounts recognized in the statement of financial position as of December 31 of both years: 1999 1998 -------- -------- (in thousands) Accrued benefit liability $ (8,486) $ (7,649) Intangible asset 1,933 1,307 -------- -------- Net amount recognized $ (6,553) $ (6,342) ======== ======== The assumptions used for actuarial valuations were: 1999 1998 -------- -------- Discount rate 7.75% 6.50% Rate of increase in future compensation level 4.00% 5.00% In addition to providing pension benefits, the electric utility provides a portion of health insurance benefits for retired electric utility employees. Substantially all of the Company's electric utility employees may become eligible for health insurance benefits if they reach age 55 and have 10 years of service. Upon adoption of SFAS 106 - Employers' Accounting for Postretirement Benefits Other Than Pensions - in January 1993, the Company elected to recognize its transition obligation related to postretirement benefits earned of approximately $14,964,000 over a period of 20 years. There are no plan assets. The net periodic postretirement benefit cost for 1999, 1998, and 1997 includes the following components: 1999 1998 1997 -------- -------- ------- (in thousands) Service cost - benefit earned during the period $ 753 $ 563 $ 578 Interest cost on accumulated postretirement benefit obligation 1,432 1,281 1,159 Amortization of transition obligation 748 748 748 Amortization of prior service cost 111 -- -- Amortization of net gain -- (209) (251) ------ ------ ------ Net periodic postretirement benefit cost $3,044 $2,383 $2,234 1998 early retirement and curtailment -- 954 -- ------ ------ ------ Total $3,044 $3,337 $2,234 ====== ====== ====== The following tables provide a reconciliation of the changes in the plan's benefit obligations over the two-year period ending December 31, 1999 and a statement of the funded status as of December 31 of both years: 1999 1998 -------- -------- (in thousands) Reconciliation of benefit obligation: Obligation at January 1 $ 23,628 $ 17,707 Service cost 753 563 Interest cost 1,432 1,281 Actuarial (gain)/loss (4,444) 4,726 Benefit payments (1,555) (1,412) Participant premium payments 437 492 1998 early retirement and curtailment -- 271 -------- -------- Obligation at December 31 $ 20,251 $ 23,628 ======== ======== Funded status: Funded status at December 31 $(20,251) $(23,628) Unrecognized transition obligation 9,726 10,474 Unrecognized prior service cost 596 -- Unrecognized (gain) loss (4,348) 802 -------- -------- Net amount recognized $(14,277) $(12,352) ======== ======== The amounts recognized in the statement of financial position as of December 31 of both years: 1999 1998 -------- -------- (in thousands) Accrued benefit liability $(14,277) $(12,352) The assumed health-care cost-trend rate used in measuring the accumulated postretirement benefit obligation as of December 31, 1999, was 7.0 percent for 2000, decreasing linearly each successive year until it reaches 5.0 percent in 2003, after which it remains constant. The assumed health-care cost-trend rate used in measuring the accumulated postretirement benefit obligation as of December 31, 1998, was 7.5 percent for 1999, decreasing linearly each successive year until it reaches 5.0 percent in 2003, after which it remains constant. The assumed discount rate used in determining the accumulated postretirement benefit obligation as of December 31, 1999 and 1998, was 7.75 percent and 6.5 percent, respectively. Assumed health-care cost-trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health-care cost-trend rates for 1999 would have the following effects: 1 percent 1 percent increase decrease --------- --------- Effect on total of service and interest (in thousands) cost components $ 399 $ (332) Effect on the postretirement benefit obligation $ 1,637 $ (3,194) The Company has a leveraged employee stock ownership plan (ESOP) for the benefit of all its electric utility employees. Contributions made by the Company were $1,110,000 for 1999, $1,078,000 for 1998, and $1,055,000 for 1997. 11. Compensating balances and short-term borrowings The Company maintains formal bank lines of credit for its electric utility operations separate from lines and letters of credit maintained by the diversified companies. The lines of credit make available to the Company bank loans for short-term financing and provide backup financing for commercial paper notes. At December 31, 1999, the Company maintained no compensating balances to support formal bank lines of credit. The Company's bank lines of credit for electric utility operations totaled $18,000,000, none of which was used at December 31, 1999. The diversified companies' bank lines and letters of credit, which require no compensating balances, totaled $14,725,000, none of which was used at December 31, 1999. 12. Fair value of financial instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Cash and short-term investments--The carrying amount approximates fair value because of the short-term maturity of those instruments. Other investments--The carrying amount approximates fair value. A portion of other investments is in financial instruments that have variable interest rates that reflect fair value. The remainder of other investments is accounted for by the equity method which, in the case of operating losses, results in a reduction of the carrying amount. Redeemable preferred stock--The fair value is estimated based on the current rates available to the Company for the issuance of redeemable preferred stock. Long-term debt--The fair value of the Company's long-term debt is estimated based on the current rates available to the Company for the issuance of debt. About $20 million of the Company's long-term debt, which is subject to variable interest rates, approximates fair value.
1999 1998 ---------------------- --------------------- (in thousands) Carrying Fair Carrying Fair amount value amount value -------- -------- -------- -------- Cash and short-term investments $ 24,762 $ 24,762 $ 3,919 $ 3,919 Other investments 19,502 19,502 20,612 20,612 Redeemable preferred stock (18,000) (17,650) (18,000) (19,252) Long-term debt (176,437) (176,677) (181,046) (203,789)
The Company's marketable securities are included in investments on the balance sheet and are classified as available for sale. These securities are recorded at fair value with any unrealized gain or loss included in accumulated other comprehensive income in the equity section of the balance sheet net of deferred income taxes of $210,000 at year-end 1998. Realized gains and losses are computed on each specific investment sold. The amounts recognized on the balance sheet as of December 31, 1999 and 1998, and amounts sold for each year are as follows: 1999 1998 -------- -------- Available for sale - securities (in thousands) Cost $ -- $ 83 Gross unrealized gain -- 507 -------- ------- Fair value $ -- $ 590 ======== ======= Proceeds from sale $ 1,566 $ -- Gross realized gains 1,483 -- 13. Property, plant, and equipment 1999 1998 -------- -------- (December 31, in thousands) Electric plant: Production $309,761 $309,109 Transmission 151,581 143,822 Distribution 242,130 234,671 General 75,565 83,285 ------- ------- Electric plant 779,037 770,887 Less accumulated depreciation and amortization 342,915 332,315 ------- ------- Electric plant net of accumulated depreciation 436,122 438,572 Construction work in progress 10,979 10,495 ------- ------- Net electric plant $447,101 $449,067 ------- ------- Diversified operations plant $ 99,558 $ 89,094 Less accumulated depreciation and amortization 43,703 37,975 ------- ------- Net diversified operations plant $ 55,855 $ 51,119 ------- ------- Net plant $502,956 $500,186 ======= =======
14. Income taxes The total income tax expense differs from the amount computed by applying the federal income tax rate (35 percent in 1999, 1998 and 1997) to net income before total income tax expense for the following reasons: 1999 1998 1997 -------- -------- -------- (in thousands) Tax computed at federal statutory rate $24,112 $18,272 $16,329 Increases (decreases) in tax from: State income taxes net of federal income tax benefit 2,607 2,665 2,224 Investment tax credit amortization (1,186) (1,186) (1,186) Depreciation differences--flow-through method reversal 82 1,133 408 Differences reversing in excess of federal rates (466) (1,639) (994) Dividend received/paid deduction (667) (643) (620) Affordable housing tax credits (1,393) (1,330) (1,057) Permanent and other differences 826 413 (796) ------- ------- ------- Total income tax expense $23,915 $17,685 $14,308 ======= ======= ======= Overall effective federal and state income tax rate 34.7% 33.9% 30.7% Income tax expense includes the following: Charges (credits) related to operations: Current federal income taxes $25,823 $20,198 $17,123 Current state income taxes 5,182 4,182 3,300 Deferred federal income taxes (3,336) (4,085) (3,410) Deferred state income taxes (450) (206) (205) Investment tax credit amortization (1,186) (1,186) (1,186) ------- ------- ------- Total $26,033 $18,903 $15,622 Charges (credits) related to other income and deductions: Current federal income taxes (459) (280) (645) Affordable housing tax credits (1,393) (1,330) (1,057) Current state income taxes (145) (9) 19 Deferred federal and state income taxes (121) 401 369 ------- ------- ------- Total income tax expense $23,915 $17,685 $14,308 ======= ======= =======
The Company's deferred tax assets and liabilities were composed of the following on December 31, 1999 and 1998: 1999 1998 -------- -------- (in thousands) Deferred tax assets Amortization of tax credits $ 10,601 $ 11,497 Vacation accrual 1,286 1,202 Unearned revenue 1,563 1,844 Operating reserves 11,093 10,026 Differences related to property 2,392 2,209 Transfer to regulatory asset -- 124 Transfer to regulatory liability 496 -- Other 1,353 991 -------- -------- Total deferred tax assets $ 28,784 $ 27,893 -------- -------- Deferred tax liabilities Differences related to property (106,976) (108,968) Transfer to regulatory asset (4,110) (3,744) Other (2,547) (3,415) -------- -------- Total deferred tax liabilities $(113,633) $(116,127) -------- -------- Deferred income taxes $ (84,849) $ (88,234) ======== ======== 15. Subsequent Events Effective January 1, 2000, the Company through Varistar acquired the assets and operations of Vinyltech Corporation (Vinyltech) located in Phoenix, Arizona. Vinyltech is a manufacturer of PVC pipe and produces approximately 90 million pounds of pipe annually. Annual revenues for 1999 were approximately $41 million. The acquisition will be accounted for using the purchase method of accounting. The excess of the purchase price over the net assets acquired of approximately $22 million will be amortized over 15 years. Vinyltech sells PVC pipe in Arizona, California, Nevada and other southwestern states. On January 31, 2000, the Company's board of directors declared a two-for-one common stock split to be effected in the form of a 100 percent stock dividend payable on March 15, 2000 to holders of record on February 15, 2000. Accordingly, 1999 balances reflect the stock split with an increase in common shares of $59,625,000 and reductions in premium on common shares and retained earnings of $41,760,000 and $17,865,000, respectively. All stock options, share and per-share data has been restated to reflect the stock split.
16. Quarterly information (unaudited) Three Months Ended March 31 June 30 September 30 December 31 -------------------- -------------------- -------------------- ------------------- 1999 1998 1999 1998 1999 1998 1999 1998 -------- -------- -------- -------- -------- -------- -------- -------- (in thousands except per share data) Operating revenues $111,485 $97,143 $112,397 $107,470 $123,619 $112,831 $117,076 $115,708 Operating income $ 17,688 $ 5,736 $ 14,604 $ 14,948 $ 18,861 $ 18,227 $ 16,213 $ 19,625 Income before cumulative effect of change in accounting principle $ 9,249 $ 1,939 -- -- -- -- -- -- Cumulative effect of change in accounting principle -net-of-tax $ -- $ 3,819 -- -- -- -- -- -- -------- ------- Net income $ 9,249 $ 5,758 $ 7,146 $ 8,015 $ 10,380 $ 9,877 $ 18,202 $ 10,870 Earnings available for common shares $ 8,659 $ 5,168 $ 6,557 $ 7,426 $ 9,801 $ 9,287 $ 17,732 $ 10,281 Basic and diluted earnings per share Before cumulative effect of change in accounting principle $ .36 $ .06 -- -- -- -- -- -- Cumulative effect of change in accounting principle $ -- $ .16 -- -- -- -- -- -- -------- ------- Basic and diluted earnings per share $ .36 $ .22 $ .28 $ .32 $ .41 $ .39 $ .74 $ .43 Dividends paid per common share $ .2475 $ .24 $ .2475 $ .24 $ .2475 $ .24 $ .2475 $ .24 Price range: High $22 3/8 $19 3/8 $21 3/16 $18 7/8 $22 3/4 $20 3/8 $22 25/32 $21 3/8 Low $17 $18 $19 $15 1/16 $19 $17 1/2 $18 3/4 $18 1/2 Average number of common shares outstanding 23,780 23,481 23,845 23,554 23,850 23,637 23,851 23,710 The fourth quarter of 1999 includes a $14.5 million ($8.1 million net-of-tax) gain from the sale of the radio station assets. In the first quarter of 1998 the Company changed its method of electric revenue recognition in the states of Minnesota and South Dakota from meter-reading dates to energy-delivery dates resulting in the recognition of $6,364,000 ($3,819,000 net-of-tax) in unbilled revenue. The first quarter of 1998 also reflects the recording of special charges related to the voluntary early retirement program, Quadrant Co. asset impairment and the write-off of the Big Stone plant rail spur project. - ---------------------------------------------------------------------------------------------------------------------------------
Stock Listing - -------------- Otter Tail common stock is traded on The Nasdaq Stock Market. (Nasdaq: National Association of Securities Dealers Automated Quotation.) EX-21 8 Exhibit 21-A OTTER TAIL POWER COMPANY Subsidiaries of the Registrant March 1, 2000 Company State of Organization Minnesota-Dakota Generating Company Minnesota Otter Tail Realty Company Minnesota Otter Tail Management Corporation* Minnesota ORD Corporation* Minnesota Quadrant Co.* Minnesota Midwest Information Systems, Inc. Minnesota Midwest Telephone Co. Minnesota Osakis Telephone Company Minnesota The Peoples Telephone Company of Bigfork Minnesota Data Video Systems, Inc. Minnesota Otter Tail Communications SD, Inc. South Dakota MIS Investments, Inc. Minnesota Varistar Corporation Minnesota Precision Machine, Inc. Minnesota Dakota Machine, Inc. North Dakota Dakota Engineering, Inc.* North Dakota Aerial Contractors, Inc. North Dakota Moorhead Electric, Inc. Minnesota Diagnostic Medical Systems, Inc. North Dakota DMS Imaging, Inc. North Dakota DMS Leasing Corporation North Dakota BTD Manufacturing, Inc. Minnesota Northern Pipe Products, Inc. North Dakota Northern Micro, Inc. North Dakota Fargo Baseball, LLC Minnesota Fargo Sports Concession LLC Minnesota Chassis Liner Corporation Minnesota Chassis Liner Credit Corp. * Minnesota Otter Tail Energy Services Company, Inc. Minnesota Mid-States Testing Company Minnesota Otter Tail Energy Management Company Minnesota E. W. Wylie Corporation North Dakota Vinyltech Corporation Arizona *Inactive EX-23 9 EXHIBIT 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 333-11145 on Form S-3 and 333-25261, 333-73041, 333-73075 on Form S-8 of Otter Tail Power Company of our report dated January 31, 2000, incorporated by reference in this Annual Report on Form 10-K of Otter Tail Power Company for the year ended December 31, 1999. Deloitte & Touche LLP Minneapolis, Minnesota March 28, 2000 EX-24 10 EXHIBIT 24 POWER OF ATTORNEY __________ I, JEFFREY J. LEGGE, do hereby constitute and appoint JOHN C. MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, and or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Controller and Principal Accounting Officer of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1999, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: January 6, 2000. ---------------- /s/ Jeff Legge ------------------------- Jeff Legge In Presence of: Kathy Legge - ------------------------ Anita Anderson - ------------------------ POWER OF ATTORNEY __________ I, JOHN C. MAC FARLANE, do hereby constitute and appoint JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as President and Chief Executive Officer, Principal Executive Officer and Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1999, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: January 5, 2000. ---------------- /s/ John MacFarlane ------------------------- John MacFarlane In Presence of: Lori D. Dawkins - ------------------------ Penny Mosher - ------------------------ POWER OF ATTORNEY __________ I, ROBERT N. SPOLUM, do hereby constitute and appoint JOHN C. MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1999, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: January 10, 2000. ----------------- /s/ Robert N. Spolum ------------------------- Robert N. Spolum In Presence of: Francine C. Johnson - ------------------------ W. T. Todd - ------------------------ POWER OF ATTORNEY __________ I, NATHAN I. PARTAIN, do hereby constitute and appoint JOHN C. MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1999, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: January 18, 2000. ----------------- /s/ Nathan I. Partain ------------------------- Nathan I. Partain In Presence of: Eric Elvekrog - ------------------------ Ellen Rembert - ------------------------ POWER OF ATTORNEY __________ I, DAYLE DIETZ, do hereby constitute and appoint JOHN C. MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1999, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: January 15, 2000. ----------------- /s/ Dayle Dietz ------------------------- Dayle Dietz In Presence of: Stan Stroh - ------------------------ Penny Mosher - ------------------------ POWER OF ATTORNEY __________ I, ARVID R. LIEBE, do hereby constitute and appoint JOHN C. MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1999, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: January 7, 2000. ---------------- /s/ Arvid R. Liebe ------------------------- Arvid R. Liebe In Presence of: Renee Thomas - ------------------------ Beth M. Folk - ------------------------ POWER OF ATTORNEY __________ I, THOMAS M. BROWN, do hereby constitute and appoint JOHN C. MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1999, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: January 7, 2000. ---------------- /s/ Thomas M. Brown ------------------------- Thomas M. Brown In Presence of: Donna M. Hull - ------------------------ Marla Larson - ------------------------ POWER OF ATTORNEY __________ I, MAYNARD D. HELGAAS, do hereby constitute and appoint JOHN C. MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1999, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: January 17, 2000. ----------------- /s/ Maynard D. Helgaas ------------------------- Maynard D. Helgaas In Presence of: Carrie Horsted - ------------------------ Elaine Hazelton - ------------------------ POWER OF ATTORNEY __________ I, KENNETH L. NELSON, do hereby constitute and appoint JOHN C. MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1999, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: January 17, 2000. ----------------- /s/ Kenneth L. Nelson ------------------------- Kenneth L. Nelson In Presence of: Mike Holper - ------------------------ Wayne Cagheny - ------------------------ POWER OF ATTORNEY __________ I, DENNIS R. EMMEN, do hereby constitute and appoint JOHN C. MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1999, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: January 17, 2000. ----------------- /s/ Dennis R. Emmen ------------------------- Dennis R. Emmen In Presence of: Dee Fletcher - ------------------------ Deborah A. Kleven - ------------------------ POWER OF ATTORNEY __________ I, JOHN D. ERICKSON, do hereby constitute and appoint JOHN C. MAC FARLANE, and C. E. BRUNKO, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Vice President, Finance of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1999, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: January 19, 2000. ----------------- /s/ John Erickson ------------------------- John Erickson In Presence of: Penny Mosher - ------------------------ Becky Luhning - ------------------------ EX-27 11
UT EXHIBIT 27 This schedule contains summary financial information extracted from the Consolidated Balance Sheet as of December 31, 1999, and the Consolidated Statement of Income for the twelve months ended December 31, 1999, and is qualified in its entirety by reference to such financial statements. 1,000 12-MOS DEC-31-1999 DEC-31-1999 PER-BOOK 447,101 104,809 119,936 8,942 0 680,788 119,250 (301) 126,744 245,693 18,000 15,500 176,437 0 0 0 5,948 0 0 0 219,210 680,788 464,577 23,915 397,211 421,126 43,451 16,297 59,748 14,771 44,977 2,228 42,749 23,554 14,232 78,325 1.79 1.79 Per-share data reflects the effects of the two-for-one stock split effective March 15, 2000. Prior Financial Data Schedules have not been restated to reflect the stock split.
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