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.
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.
Item 3. LEGAL PROCEEDINGS ----------------- Not Applicable.
Item 4.
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.
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.
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.
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.
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.
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.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND --------------------------------------------------------------- FINANCIAL DISCLOSURE --------------------
None.
PART III
Item 10.
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.
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.
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.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ----------------------------------------------
None.
PART IV
Item 14.
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
-----------------
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.