Item 1. BUSINESS
(a) General Development of Business
Otter Tail Power Company (the "Company") is an operating public utility which was incorporated in 1907 under the laws of the State of Minnesota. Its principal executive office is located at 215 South Cascade Street, Box 496, Fergus Falls, Minnesota 56538-0496; and its telephone number is (218) 739- 8200.
The Company's primary business is the production, transmission, distribution and sale of electric energy. The Company, through its subsidiaries, is also engaged in other businesses which are referred to as Health Services Operations and Diversified Operations. Health Services Operations consists of certain businesses acquired in 1993, including a diagnostic medical imaging company, a management company for a number of diagnostic medical imaging companies, and a medical imaging company that sells and services diagnostic medical imaging equipment and associated supplies and accessories. Diversified Operations consists of businesses diversified in such areas as manufacturing (fabricated metal parts and agricultural equipment), electrical and telephone contracting, radio broadcasting, waste incinerating, and telephone/cable TV utility.
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 24 through 31 of the Company's 1993 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 three segments: Electric Operations, Health Services Operations, and Diversified Operations. Financial information about the Company's industry segments is incorporated by reference to note 2 of "Notes to Consolidated Financial Statements" on page 39 of the Company's 1993 Annual Report to Shareholders, filed as an Exhibit hereto.
(c) Narrative Description of Business
ELECTRIC OPERATIONS
General
On a fully consolidated basis, the Company derived 73% of its operating revenues from the sale of electric energy during 1993; 85% during 1992; and 90% during 1991. During 1993 the Company derived approximately 54.5% of its electric revenues from Minnesota, 38.4% from North Dakota, and 7.1% 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, 51.7% of 1993 electric revenues was derived from commercial and industrial customers, 32.6% from residential customers, and 15.7% from other sources, including municipalities, farms and power pools.
The Company's two largest oil pipeline customers accounted for about 10.4% of total 1993 retail electric revenues compared to 10.5% of such revenues in 1992. In 1993, retail kwh sales to these pipeline customers increased by 4.2% from the previous year. Sales to a large wood products customer accounted for 1.6% of total retail electric revenues in 1993 as compared to 1.7% in 1992. Sales to a large barley malting plant accounted for 1.4% of total retail electric revenues in 1993 as compared to 1.7% in 1992. No other retail customer accounted for more than 1% of retail electric revenues. Power pool sales to other utilities, which accounted for 26.8% of total 1993 kwh sales, increased 72.9% from 1992. The increase in power pool sales in 1993 can be attributed to the weather, which resulted in low water conditions in the spring in Manitoba and widespread summer flooding in the Midwest. Activity in short-term energy sales is subject to change based on a number of factors and the Company is unable to predict the 1994 level of activity. The Company's other sales of electricity for resale are insignificant.
The aggregate population of the Company's retail service area is approximately 230,000. In this service area of 423 communities and adjacent rural areas and farms, approximately 123,600 people lived 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 121,287, the Company has experienced an increase in customers. By year end 1993 total customers had increased to 122,427. During 1993, the Company experienced a net increase of 430 customers, with growth in the number of residential and commercial customers, notwithstanding the loss of 243 customers to the city of Detroit Lakes, Minnesota as a result of annexation of a portion of the Company's service territory.
The Company's electric sales are subject to competition in some areas from municipally owned systems, rural 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. Although the Company cannot predict the precise extent to which its future business may be affected by supply, relative cost or promotion of other electricity or energy suppliers, the Company believes that it will be in a position to compete favorably with other suppliers.
Rate Matters
The Company is subject to electric rate regulation as follows:
Year Ended December 31, 1993 % of Electric % of kwh Rates Regulation Revenues Sales
Minnesota retail sales Minnesota Public Utilities Commission 46.4% 38.7% North Dakota retail sales North Dakota Public Service Commission 36.7 28.9 South Dakota retail sales South Dakota Public Utilities Commission 7.0 5.4 Transmission and sales Federal Energy Regulatory for resale Commission ("FERC") 9.9 27.0 100.0% 100.0% The following table summarizes the electric rate proceedings with the Minnesota and the South Dakota Public Utilities Commissions, the North Dakota Public Service Commission, and the Federal Energy Regulatory Commission since January 1, 1989:
Increase % Increase Increase (Decrease) Granted Request (Decrease) (Decrease) Commission Filed Requested Effective Amount % (Thousands)
Minnesota Last Proceeding was July 1, 1987
North Dakota (1). . . . . January 15, 1989 ($1,000) (1.5%) (2). . . . . June 1, 1990 ($ 315) (0.5%) (3). . . . . September 9, 1992 ($1,000) (1.5%) (4). . . . . September 22, 1993 ($ 300) (0.4%)
South Dakota Last Proceeding was November 1, 1987
FERC Last Proceeding was July 1, 1987
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(1) A voluntary settlement agreement reached between the Company and the North Dakota Commission decreased North Dakota retail rates by $1,000,000 annually (or approximately 1.5%) effective January 15, 1989. In addition, the settlement agreement provided for the Company to spend $315,000 annually on additional North Dakota economic development, which expenditures will be offset by reduced North Dakota depreciation expense. (2) This voluntary rate adjustment decreased North Dakota retail rates by $315,000 annually to recognize the positive effect on the Company's customer base in North Dakota as a result of the economic development expenditures referred to in note (1) above. (3) A voluntary settlement agreement reached between the Company and the North Dakota Commission pursuant to which the Company made a refund of $1,000,000 to its North Dakota customers. This settlement does not require a permanent reduction in rates charged by the Company to customers in North Dakota. (4) An agreement for incentive regulation reached between the Company and the North Dakota Commission provides for sharing equally between ratepayers and shareholders any amount earned in 1993 over or under a benchmark overall rate of return. A liability of $300,000 for the Company to its North Dakota customers resulted from sharing earnings above this benchmark for 1993. The status of this liability will be considered in future incentive agreements between the Company and the North Dakota Commission for the years 1994 and following.
Under Minnesota law, the Minnesota Commission must allow implementation of an interim rate increase, subject to refund with interest, 60 days after the initial filing date of a rate increase request, except that the Commission 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 Commission, and rate base and expense items allowed by a currently effective Commission order. In addition, if the Commission 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 (i) 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 Commission on the last day of the extended period of suspension of the rate increase, or (ii) a settlement has been submitted to and rejected by the Commission, and the Commission 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 60 days after the initial or, if applicable, the extended period of suspension of the rate increase.
Rate requests filed with the North Dakota Public Service Commission become effective 30 days after the date of filing unless suspended by the Commission. Within seven months after the date of suspension, the North Dakota Commission must act on the request, and during the period of consideration by the Commission a suspended rate can be implemented only with the approval of the Commission.
South Dakota law provides that a requested rate increase can be implemented 30 days after the date of filing, unless its effectiveness is suspended by the Commission. The Commission may suspend the effectiveness of the proposed rate change for a period not longer than 90 days beyond the time when the rate change would otherwise go into effect, unless the Commission finds that a longer time is required, in which case the Commission may extend the suspension for a period not to exceed a total of 12 months. A public utility may not put a proposed rate change into effect until at least 45 days after the Commission has made a determination concerning any previously filed rate change. In the event that a requested rate change is suspended by the Commission, such requested rate change can be implemented by the public utility six months after the date of filing (unless previously authorized by the Commission), subject to refund with interest.
The Company's wholesale power sales and transmission rates are subject to the jurisdiction of the Federal Energy Regulatory Commission under the Federal Power Act of 1935. Filed rates are effective after a one-day suspension period, subject to ultimate approval by the FERC. Power pool sales are conducted continuously through the Mid-Continent Area Power Pool ("MAPP") on the basis of generating costs, in accordance with schedules filed by MAPP with the FERC.
In rate cases, a forward test year procedure enables cost increases to be recovered more promptly than use of an historic test year. The Minnesota Public Utilities Commission has established by regulation a forward test year procedure. The North Dakota Public Service Commission has not formally established a test year procedure; however, it accepted a forward test year in the Company's most recent rate case. The South Dakota Public Utilities Commission uses an historic test year with adjustments for known and measurable changes occurring within 24 months of the last month of the test year.
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, 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 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 the energy charge for electric power purchased by the Company. Such adjustments are presently based upon a two-month moving average in Minnesota and under the FERC, 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.
Capability and Demand
At December 31, 1993, the Company had base load net plant capability totaling 550,869 kw, consisting of 242,874 kw from the Big Stone Plant (the Company's 53.9% share), 153,175 kw from the Hoot Lake Plant, 149,450 kw from the Coyote Plant (the Company's 35% share), and 5,370 kw from the Potlatch Co- generation Plant near Bemidji, Minnesota (the Company's 50% share). In addition to its base load capability, the Company has internal combustion units and small diesel units, used chiefly for peaking and standby purposes, with a total capability of 87,993 kw, and 4,030 kw of hydroelectric capability. During 1993, the Company generated about 76% 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 Northern States Power Company ("NSP") for the annual exchange of 75,000 kw of seasonal diversity capacity. Pursuant to this agreement, NSP began providing the Company with 75,000 kw of capacity for winter seasons on November 1, 1990, and the Company started providing NSP with 75,000 kw of summer capacity on May 1, 1991. This is a fifteen-year agreement which provides the Company a means of increasing the capacity of its winter peaking system and better coordinates use of its generating facilities with no additional investment. In addition, for the 1993-1994 winter season, the Company purchased 20,000 kw of capacity from Lincoln Electric System ("LES"). The Company has extended its winter season agreement with LES through the 1994-1995 winter season. The Company has an agreement with Manitoba Hydro Electric Board to purchase 110,000 kw of capacity for the summer seasons of 1994 through 1996. The Company also has a direct control load management system which provides some flexibility to the Company to effect reductions of peak load.
The Company is a member of the Mid-Continent Area Power Pool ("MAPP"), which includes 46 investor-owned utilities, rural cooperatives, municipal utilities, and other power suppliers in the North Central region of the United States and in two Canadian provinces. The objective of MAPP is to coordinate planning and operation of generating 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 buy and sell power among each other according to differing peak demands.
The Company is a winter peaking utility and traditionally experiences its peak system demand during the winter season. For the calendar year 1993, the Company established a new record sixty-minute peak demand of 589,239 kw on January 8, 1993. Taking into account additional capacity available to it in January 1993 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 741,623 kw. In 1994 the Company expects moderate growth in peak demand as compared to 1993. Due to very cold temperatures it is likely that a new record sixty-minute peak demand was set early in 1994. 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, are expected to meet 1994 system demand, including industry reserve requirements.
Fuel Supply
Lignite coal is the principal fuel burned by the Company at its Big Stone and Coyote generating plants. The majority of coal burned at the Hoot Lake Plant since 1988 has been western subbituminous coal. The following table shows for 1993 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
Lignite Coal . . . . . . . . . . . . . 2,251,572 82.1% Subbituminous Coal . . . . . . . . . . 466,458 17.0 Hydro . . . . . . . . . . . . . . . . . 25,719 .9 Oil . . . . . . . . . . . . . . . . . . 673 - Total . . . . . . . . . . . . . . . 2,744,422 100.0%
The Company's supply of lignite coal (all of which comes from North Dakota) is furnished by Knife River Coal Mining Company (a subsidiary of Montana-Dakota Utilities Co., a co-owner of the Big Stone and Coyote Plants). The Company has a contract for sufficient lignite coal to supply the Big Stone Plant until 1995, with an option to renew for an additional 20 years subject to certain contingencies. In 1992 the parties reached an agreement which resulted in lower coal costs for the life of the contract. The Company has a contract running through 1999 with Knife River Coal Mining Company for sufficient lignite coal to operate its Hoot Lake Plant. The Company has negotiated purchase agreements for fixed quantities of subbituminous coal as needed for Hoot Lake Plant. The lignite coal contract with Knife River Coal Mining Company for the Coyote Plant expires in 2016, with a 15-year renewal option subject to certain contingencies, and is expected to provide the plant's lignite coal requirements during the term of the contract.
It is the Company's practice to maintain minimum 30-day inventories (at full output) of coal at the Big Stone and Coyote Plants, and a 10-day inventory at the Hoot Lake Plant.
The lignite coal used at Big Stone Plant is transported in unit train cars belonging to the plant owners. The coal transportation contract for the Big Stone Plant with the Burlington Northern Railroad expires in 1995. A freight rate reduction was negotiated for lignite deliveries to the Big Stone Plant, effective in March 1990.
Transportation costs of lignite coal to Hoot Lake Plant are governed by tariffs established pursuant to authority of the Interstate Commerce Commission. The existing contract with Burlington Northern Railroad for subbituminous coal deliveries at Hoot Lake was amended in 1993 and will remain in effect for 1994 with annual renewals by mutual agreement. The Company also has a subbituminous coal transportation agreement with Northern Coal Transportation Company effective January 1993 covering coal moved from Kennecott Energy's Spring Creek Mine to Hoot Lake Plant. This agreement expires January, 1996. Freight rates were reduced in 1993 under both agreements.
The Coyote Plant is a mine-mouth plant located in western North Dakota, near the source of lignite coal used for generation. Because there are no coal transportation costs, this plant has a relatively low fuel cost compared to other Company units.
The average cost of coal consumed (including handling charges to the plant sites) in cents per million BTU for each of the three years 1993, 1992 and 1991, was 100.7 cents, 100.5 cents and 104.1 cents, respectively. The average cost of coal consumed (including handling charges to the plant sites) per ton for each of the three years 1993, 1992 and 1991 was $13.75, $13.33 and $13.60, respectively.
North Dakota imposes a severance tax on lignite at a flat rate of $ .75 per ton, plus an additional $ .02 per ton which is deposited in a lignite research fund. The lignite coal used by the Company at its plants is surface mined. The North Dakota laws relating to surface mining and the Federal Surface Mining Control and Reclamation Act will continue to adversely affect the price of lignite to the Company. Any increased costs of lignite would be substantially recovered through the provisions in the Company's rate schedules for adjustments in rates based upon the cost of fuel delivered to the Company's generating plants. See "Rate Matters."
During 1990, the Company conducted test burns of tire-derived fuel ("TDF") at the Big Stone Plant and has received approval from the South Dakota Department of Environment and Natural Resources to burn TDF. The quantity of TDF burned as fuel during 1993 (1.6% of total fuel burned at the Big Stone Plant), and expected to be burned in 1994, is insignificant when compared to the lignite coal consumption at the Big Stone Plant. During 1991, test burns of refuse derived fuel ("RDF") were conducted at Big Stone Plant and approval to burn RDF as fuel was granted by the South Dakota Department of Environment and Natural Resources. The quantity of RDF burned in 1993 (.8% of total fuel burned at the Big Stone Plant) and expected to be burned in 1994 is insignificant when compared to Big Stone Plant's lignite coal consumption.
General Regulation
Under the Minnesota Public Utilities Act, the Company is subject to the jurisdiction of the Minnesota Public Utilities Commission ("MPUC") with respect to rates, issuance of securities, 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 Minnesota Department of Public Service ("DPS") is responsible for investigating all matters subject to the jurisdiction of the DPS or the MPUC, and for the enforcement of MPUC orders. Among other things, the DPS is authorized to collect and analyze data on energy and the consumption of energy, develop recommendations as to energy policies for the Governor and the Legislature of Minnesota and evaluate policies governing the establishment of rates and prices for energy as related to energy conservation. The DPS acts as state advocate in matters heard before the MPUC. The DPS 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% of its gross operating revenues from service provided in Minnesota. The DPS 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 DPS 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 be in the property owner rather than the utility. The Company is required to submit, and the MPUC has approved, the Company's incentive mechanism for recovery of conservation related expenditures for 1992 and 1993. The MPUC requires the submission of a 15-year advance integrated resource plan by jurisdictional utilities. The Company submitted its first plan in 1992, which was approved by the MPUC in 1993, and will be required to submit its next plan in 1994.
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.
The Company is subject to the jurisdiction of the Public Service Commission of North Dakota with respect to rates, services, certain issuances of securities and other matters. The North Dakota Energy Conversion and Transmission Facility Siting Act grants the North Dakota Commission 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 115 kv or more.
The South Dakota Public Utilities Act subjects the Company to the jurisdiction of the South Dakota Public Utilities Commission 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 Commission with respect to the issuance of securities. Under the South Dakota Energy Facility Permit Act, the South Dakota Commission 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.
The Company is also subject to regulation by the Federal Energy Regulatory Commission, successor to the Federal Power Commission, created pursuant to the Federal Power Act of 1935, as amended. 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.
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 which 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 standards and regulations regarding, among other things, air, water and solid waste pollution, by agencies of the federal government and the respective states where the Company's plants are located. The Company estimates that it has expended in the five years ended December 31, 1993, approximately $9,700,000 for environmental control facilities (excluding allowance for funds used during construction). Included in the 1994-1998 construction budget are approximately $980,000 for environmental improvements for existing and new facilities, including $500,000 for 1994.
Air Quality Pursuant to the Federal Clean Air Act of 1970, the Clean Air Act Amendments of 1990 and other amendments thereto (collectively 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 with sulfur content averaging less than one percent. Electrostatic precipitators have been installed at the Company's 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 Company's units at Big Stone and Hoot Lake currently meet all federal and state air quality and emission standards presently applicable.
The Coyote Plant 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 desulphurize hot gases from the stack without producing sludge, an unwanted by-product of the conventional wet scrubber system. The Coyote Plant is currently operating within all presently applicable federal and state air quality and emission standards.
The Clean Air Act Amendments of 1990, in addressing acid deposition, will impose new requirements on power plants in an effort to reduce national emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx).
The national SO2 emission reduction goals are to be achieved through a new market-based system under which power plants are to be 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 will be imposed in two phases, the first to take effect in 1995 and the second in 2000.
The phase one requirements do not apply to any of the Company's plants. The phase two standards apply to the Company's plants in the year 2000. The Company believes that its current use of low sulfur coal at the Hoot Lake Plant and the dry scrubbers installed at the Coyote Plant will enable the facilities to comply with anticipated phase two limitations with regards to SO2. Although the Big Stone Plant's current annual SO2 emissions meet presently applicable standards, they are higher than the levels that will be allowed by the phase two requirements. The Big Stone Plant can maintain current levels of operation and meet the phase two requirements by using allowances (alloted and/or purchased), by installing scrubbers and/or by switching to subbituminous coal which is lower in sulfur emissions than lignite which the plant currently uses. Big Stone Plant's lignite contract expires in 1995. The cost of switching to subbituminous coal from lignite would not adversely affect the Company's power plant operations based upon current market price. In the unlikely event the Company decides to continue to burn lignite, the Company's share of the cost of installing scrubbers at its Big Stone Plant by the year 2000 is estimated to be approximately $54 million.
The national NOx emission reduction goals are to be achieved by imposing mandatory emissions standards on individual sources. The standards will not apply to the Company's plants until the year 2000. Based on the NOx emissions limitations set forth in regulations recently issued by the EPA for boilers such as those used at the Company's Hoot Lake Plant, but subject to an evaluation of the results of continuous emission monitoring expected to begin at Hoot Lake in 1994, the Company currently anticipates that the cost of complying with the limitations to be applicable to Hoot Lake will not be material. The Act requires EPA to specify before January 1, 1997 the NOx limitations for cyclone boilers such as those used at Big Stone and Coyote. Because the EPA has not yet issued such regulations, the Company is unable to determine the NOx emissions limitations that will be applicable to those plants in the year 2000 or the cost to comply with such limitations.
The Clean Air Act Amendments of 1990 contain a list of toxic air pollutants to be regulated. The list 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. Because promulgation of rules by the EPA has not been completed however, 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 water 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 its Big Stone Plant. A water discharge permit for the Hoot Lake Plant was renewed in 1992 for a five year term. A renewal permit for the Coyote Plant was renewed in 1993 also 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 3,480 kw at December 31, 1993).
Solid Waste Permits for disposal of ash and other solid wastes have been issued for the Company's Big Stone and Coyote Plants. A renewal permit is pending for the Company's Hoot Lake Plant and the Company anticipates that it will obtain this renewal in due course. 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 their 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, and in 1986, reauthorized and amended the 1980 Act. 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 called 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 releases or threatened releases 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 removal of all PCB filled transformers and capacitors by the end of 1987 and received Certificates of Disposal in 1989. The Company completed removal of PCB contaminated mineral oil dielectric fluid from all substation transformers in 1991 and continues to remove such oil from voltage regulators as well as other electrical equipment.
Health Effects of Electric and Magnetic Fields 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 is funding studies. The ultimate impact, if any, of this issue on the Company and the utility industry is impossible to predict.
Franchises
At December 31, 1993, the Company had franchises in all of the 371 incorporated municipalities which 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 which the Company serves. The Company believes that the situation with regard to its franchises is satisfactory.
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 primarily in the Midwest United States. All of these business were acquired in 1993 by the Company's wholly-owned subsidiary Mid-States Development, Inc. On a fully consolidated basis, the Company derived 12% of its operating revenues from this segment in 1993.
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 manufactured primarily by Philips Medical Systems ("Philips"), including fluoroscopic, radiograhic and mammography equipment, along with ultrasound, computerized tomography ("CT") scanners, magnetic resonance imaging ("MRI") scanners, cardiac cath labs, and radiation therapy equipment for the treatment of cancer. DMS recently entered into a five year dealer agreement with Philips, which can be terminated by Philips upon eighteen months notice and certain other circumstances. DMS is also a supplier for Kodak, DuPont, and Fuji in the medical film and accessory business. DMS markets mainly to hospitals, clinics and mobile services in North Dakota, South Dakota, Minnesota, Montana and Wyoming. Almost 80% of the hospitals served by DMS have 50 or fewer beds. DMS also offers, through its subsidiaries, mobile CT and MRI service in the Upper Midwest and Central United States.
Mobile Imaging, Inc., located in Fargo, ND, and its subsidiaries are engaged primarily in providing mobile CT and MRI services in the Upper Midwest, and also provide interim scanner service on a national basis.
Imaging Plus, Inc., located in Fargo, ND, provides management, marketing and administrative services for diagnostic medical imaging companies, including Mobile Imaging, Inc. and a subsidiary of DMS.
Combined, the Health Service subsidiaries cover the three basics of the medical imaging industry: (1) operating technicians who do the imaging of patients of hospitals and clinics; (2) the equipment function that researches, buys, sells, owns, rents, refurbishes and maintains the imaging machines; and (3) central office specialists who provide scheduling, billing personnel and administrative support.
Due to the complex nature of the equipment, the diagnostic medical imaging industry is both technology intensive and capital intensive. The industry is highly competitive, with competition based primarily on the quality of the equipment and the availability of service. The Company's Health Services businesses compete with a number of other companies that make, sell, rent and service diagnostic medical imaging equipment, including large manufacturers other than Philips and their respective distributors. The Company estimates that its market share is greater than fifty percent in the Upper Midwest region.
The Company continues to investigate acquisitions of additional businesses and expects continued growth in this area.
General Regulation
Operation of the Health Services subsidiaries will be subject to the effects of pending health care legislation, the outcome of which cannot be accurately assessed at this time. As an efficient, low-cost provider of certain health services and equipment, management believes that the Health Services businesses are in line with the goals of national health-care reform.
DIVERSIFIED OPERATIONS
General
The Company's Diversified Operations consists of business that are diversified in such areas as manufacturing, electrical and telephone contracting, radio broadcasting, waste incinerating, and telephone/cable TV utility. On a fully consolidated basis, the Company derived 15% of its operating revenues from these smaller diversified business during 1993 and 1992, and 10% during 1991.
The following is a brief description of each of these businesses:
Precision Machine of North Dakota, Inc., located in West Fargo, ND, uses computer-controlled lathes and milling machines to produce parts for manufacturers.
Moorhead Electric, Inc., located in Moorhead, MN, provides commercial and industrial wiring of large buildings, constructs and maintains telecommunications and power distribution systems, and provides computer networking.
Aerial Contractors, Inc., with headquarters in West Fargo, ND, constructs and maintains overhead and underground electric, telephone, communications, and cable television lines.
Dakota Machine Tool, Inc., located in West Fargo, ND, is primarily engaged in metal fabrication of large machines that handle and refine sugar beets. Tec Steel, a division of Dakota Machine, cuts metal parts for such machines and sells the same service to other manufacturers.
Glendale Machining, Inc. of Pelican Rapids, MN, machines parts for manufacturers.
KFGO Inc. operates both AM and FM commercial radio stations broadcasting from Fargo, ND.
Quadrant Co. ("Quadrant") operates a municipal waste burning facility located in Perham, MN. Pursuant to agreements which expire in 1995, Quadrant receives a processing fee from five Minnesota counties for disposal of mixed waste and sells the steam generated from the incineration process to two customers. During 1994, Quadrant's management will be evaluating its future business plans.
Midwest Information Systems, Inc.("MIS"), headquartered in Parkers Prairie, MN, owns two operating telephone companies serving over 4000 customers and a cable television company serving approximately 600 customers. MIS is also involved in long-distance transport, fiber-optic transmission facilities and the sale of direct broadcast satellite television programming and equipment.
With the exception of Quadrant, which was founded by the Company in 1985, each of these businesses was acquired by the Company since 1989. An additional acquisition (a radio broadcasting company located in Morris, MN) was finalized in January, 1994. Quadrant is a wholly-owned subsidiary of Minnesota Dakota Generating Company ("MDG"), which in turn is a wholly-owned subsidiary of the Company. MIS is a wholly-owned subsidiary of North Central Utilities, Inc., a subsidiary of MDG formed for the purpose of acquiring regulated telephone companies. Each of the other subsidiaries described above are owned by Mid-States Development, Inc., which is also a wholly-owned subsidiary of MDG.
Each of the businesses in Diversified Operations is subject to competition, as well as the effects of general economic conditions, in their respective industries.
The Company continues to investigate acquisitions of additional businesses (both utility and nonutility) and expects continued growth in this area.
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 Minnesota DPS 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 of the Federal Communications Commission ("FCC"). The Company's operating cable television subsidiary is regulated by federal and local authorities. The Company's radio broadcasting subsidiaries are regulated by the FCC.
Environmental Regulation
The Minnesota Pollution Control Agency issued an air emission facility permit, authorizing the incineration of up to 116 tons of municipal solid waste per day at Quadrant's facility in addition to the incineration of other allowable wastes and petroleum derived used oil. The permit expired in May 1990; however the facility has been granted permission by the Minnesota Pollution Control Agency to operate under the conditions of the expired permit until operating rules for incinerators are fully developed (see discussion below). The subsidiary has formally requested a renewal of the permit.
The state of Minnesota has recently promulgated rules relating to storage, transport, testing and disposal of ash from municipal solid waste combustors, which are not expected to have a material adverse effect on the operations of Quadrant. The state of Minnesota has proposed, and the EPA is expected to propose, rules covering air emissions from municipal waste combustors of this size. Although the effects of such regulations on Quadrant's operations cannot be accurately predicted at this time, additional costs are expected to result if the regulations take effect.
CONSTRUCTION PROGRAM & FINANCING
The Company is continually expanding, replacing and improving its electric utility facilities. During 1993, the Company invested approximately $23,781,000 (including allowance for funds used during construction) for additions to its electric utility properties. During the five years ended December 31, 1993, the Company had gross electric property additions, including construction work in progress, of approximately $114,189,000 and gross retirements of approximately $27,934,000. During 1993, capital expenditures of approximately $3,000,000 were also made in each of Health Services Operations and Diversified Operations.
Total capital expenditures for the Company and its subsidiaries during the five-year period 1994-1998 are estimated to be approximately $146,000,000. Of this $14,000,000 is for Health Services Operations and $9,000,000 for Diversified Operations. The Company estimates that during the five years 1994 through 1998 it will invest for electric utility construction approximately $123,000,000 (including allowance for funds used during construction). The Company has no firm plans for additional base load construction. The majority of electric utility expenditures for the five-year period 1994 through 1998 will be for work related to the Company's transmission and distribution system.
The Company estimates that funds internally generated, combined with funds on hand, will be sufficient to provide for all of its 1994-1998 electric construction program expenditures (including allowance for funds used during construction) and to meet all sinking fund payments for First Mortgage Bonds in the next five years. Additional short or long-term financing will be required in the period 1994-1998 in connection with the maturity of First Mortgage Bonds and a Long-Term Lease Obligation ($21,000,000), in the event the Company decides to refund or retire early any of its presently outstanding debt or Cumulative Preferred Shares, to complete its Common Share repurchase program 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, competitive conditions, technological changes, new environmental and other governmental regulations, changed tax laws and rate regulation.
On October 13, 1993, the Company sold $4,000,000 of a new series of $6.75 Cumulative Preferred Shares. The proceeds were used for the redemption on November 12, 1993, of the Company's outstanding $9.50 Cumulative Preferred Shares at an aggregate redemption price of $4,080,000, plus accrued dividends to the redemption date. On November 1, 1993, the Company retired $4,970,000 of First Mortgage Bonds, 4.625% Series of 1993.
The Company sold on December 7, 1993, $3,010,000 of Industrial Development Refunding Revenue Bonds, 5% Series of 2002, and on December 15, 1993, $10,400,000 of Pollution Control Refunding Revenue Bonds, Variable Series of 2012. The proceeds were used for the redemption of the Company's First Mortgage Bonds, 7.10% Series of 2003 and 5.90% Series of 2004 in the aggregate principal amount of $13,445,000.
As of December 31, 1993, the Company had unutilized net fundable property available for the issuance of more than $13,000,000 principal amount of additional First Mortgage Bonds and also was entitled to issue in excess of $102,000,000 principal amount of additional Bonds on the basis of Bonds theretofore retired.
The Company's operating subsidiaries are responsible for obtaining their own financing after the Company's initial equity investment and have developed financing arrangements with various banks. The Company does not intend to make or guarantee loans to its subsidiaries, lend a subsidiary money or cosign on any borrowing.
The Company has access to short-term borrowing resources and has authority from the Minnesota Public Utilities Commission to have outstanding during 1994 such borrowings in an amount not to exceed $50,000,000. The Company and its subsidiaries currently have established bank lines of credit totaling $19,050,000 of which $4,437,000 was used at December 31, 1993.
EMPLOYEES
The Company and its subsidiaries had approximately 1,124 full-time employees at December 31, 1993. A total of 465 employees are represented by local unions of the International Brotherhood of Electrical Workers, of which 429 are employees of the Electrical Operations segment and are covered by a three-year labor contract expiring November 1, 1996. The Company has never experienced any strike, work stoppage, or strike vote, and regards its present relations with employees as very good.
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% interest in the plant and was the project manager in charge of construction. Montana-Dakota Utilities Co., in whose service territory the plant is located, is the operating manager of the plant.
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% of the plant.
Located near Fergus Falls, Minnesota, the Hoot Lake Plant is comprised of three separate generating units with a combined 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, 1993, the Company's transmission facilities, which are inter-connected with lines of other public utilities, consisted of 48 miles of 345 kv lines; 363 miles of 230 kv lines; 567 miles of 115 kv lines; and 4,268 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.
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.
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, 1993.
Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 1994)
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 (54) 4/8/91 Present: Chairman, President and Chief Executive Officer Prior to 4/8/91 President and Chief Executive Officer
Dennis R. Emmen (60) 4/13/81 Present: Senior Vice President, Finance,Treasurer and Chief Financial Officer
Marlowe E. Johnson (49) 4/12/93 Present: Vice President, Customer Service, North Dakota Prior to 4/12/93 Division Manager, Jamestown
Douglas L. Kjellerup (52) 4/12/93 Present: Vice President, Marketing and Development 4/8/91 Vice President, Planning and Development Prior to 4/8/91 Director, Strategic Planning and Productivity
LeRoy S. Larson (48) 4/12/93 Present: Vice President, Customer Service, Minnesota and South Dakota 4/13/92 Vice President, Division Operations, Minnesota and South Dakota Prior to 4/13/92 Division Manager, Morris
Richard W. Muehlhausen (55) 1/1/78 Present: Vice President, Corporate Services Jay D. Myster (55) 4/12/82 Present: Vice President, Governmental and Legal, and Corporate Secretary
Earl D. Sjoberg (61) 4/10/89 Present: Vice President, Electrical Prior to 4/10/89 Manager, Division Engineering
Ward L. Uggerud (44) 4/10/89 Present: Vice President, Operations Prior to 4/10/89 Director, System Operations
Andrew E. Anderson (54) 1/1/78 Present: Controller
The term of office of each of the officers is one year, and there are no arrangements or understanding between individual officers or any other persons pursuant to which he was selected as an officer.
No family relationships exist between any officers of the Company.
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 Dividends" on page 48, to first sentence under "Buying and Selling" on page 48, to "Selected Consolidated Financial Data" on page 23 and to "Quarterly Information" on page 45, of the Company's 1993 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 23 of the Company's 1993 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 24 through 31 of the Company's 1993 Annual Report to Shareholders, filed as an Exhibit hereto.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this Item is incorporated by reference to "Quarterly Information" on Page 45 and the Company's audited financial statements on Pages 32 through 45 of the Company's 1993 Annual Report to Shareholders excluding "Report of Management" on page 32, 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 is incorporated by reference from the in-formation under "Nominees for Election as Directors" in the Company's definitive Proxy Statement dated March 9, 1994. The information regarding executive officers is set forth in Item 4A hereto.
Item 11.
Item 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from the in-formation under "Summary Compensation Table", "Pension and Supplemental Retirement Plans", "Severance Agreements", "Directors' Compensation", and "Compensation Committee Interlocks and Insider Participation" in the Company's definitive Proxy Statement dated March 9, 1994.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is incorporated by reference from the in-formation under "Outstanding Voting Shares" and "Security Ownership of Management" in the Company's definitive Proxy Statement dated March 9, 1994.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated by reference from the in-formation under "Nominees for Election as Directors" in the Company's definitive Proxy Statement dated March 9, 1994.
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 20 hereof.
(3) See Exhibit Index on Pages 25 through 33 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:
No reports on Form 8-K have been filed during the quarter ended December 31, 1993.
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 D. R. Emmen D. R. Emmen Senior Vice President, Finance, Treasurer and Chief Financial Officer
Dated: March 25, 1994
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 ) ) D. R. Emmen ) Senior Vice President, Finance, ) Treasurer and Chief Financial Officer ) (principal financial officer) ) and Director ) ) Andrew E. Anderson ) By D. R. Emmen Controller ) D. R. Emmen (principal accounting officer) ) Pro Se and Attorney-in-Fact ) Dated March 25, 1994 Thomas M. Brown, Director ) ) Dayle Dietz, Director ) ) Maynard D. Helgaas, Director ) ) Kenneth L. Nelson, Director ) ) Nathan I. Partain, Director ) ) Robert N. Spolum, Director ) ) James L. Stengel, 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, 1993
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, 1993:
Page in Annual Report to Shareholders Financial Statements:
Independent Auditors' Report . . . . . . . . . . . . . . . . . 33
Consolidated Balance Sheets, December 31, 1993 and 1992 . . . 32 & 33
Consolidated Statements of Income for the Three Years Ended December 31, 1993 . . . . . . . . . . . . . . . . . . 34
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 1993 . . . . . . . . . . . . . . . . . . 35
Consolidated Statements of Retained Earnings for the Three Years Ended December 31, 1993 . . . . . . . . . . . . 35
Consolidated Statements of Capitalization, December 31, 1993 and 1992 . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Notes to Consolidated Financial Statements . . . . . . . . . . 37-45
Selected Consolidated Financial Data for the Five Years Ended December 31, 1993 . . . . . . . . . . . . . . . . . . . 23
Quarterly Data for the Two Years Ended December 31, 1993 . . . . . . . . . . . . . . . . . . . . . . 45
The following supplemental financial data included herein should be read in conjunction with the financial statements referenced above: Page in Form 10-K Independent Auditors' Report . . . . . . . . . . . . . . . . . . . 21
Supplemental Financial Schedules:
V - Property, Plant and Equipment . . . . . . . . . . . . . . 22
VI - Accumulated Provision for Depreciation and Amortization of Property, Plant and Equipment . . . . . 23
IX - Short-Term Borrowings . . . . . . . . . . . . . . . . . . . 24
Schedules other than those listed above 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.
INDEPENDENT AUDITORS' REPORT
Otter Tail Power Company:
We have audited the consolidated balance sheets and statements of capitalization of Otter Tail Power Company and its subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993, and have issued our report thereon dated January 31 1994; such consolidated financial statements and report are included in your 1993 Annual Report to Shareholders and are incorporated herein by reference. Our audits also included the financial statement schedules of Otter Tail Power Company and its subsidiaries for each of the three years in the period ended December 31, 1993, as listed in the accompanying Table of Contents. These financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE
Deloitte & Touche Minneapolis, Minnesota January 31, 1994
[TEXT] Exhibit Index to Annual Report on Form 10-K For Year Ended December 31, 1993
Previously Filed As Exhibit File No. No.
3-A --Restated Articles of Incorporation, as amended (including resolutions creating outstanding series of Cumulative Preferred Shares).
3-C 33-46071 4-B --Bylaws as amended through April 11, 1988.
4-D-1 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-6 --Thirty-First Supplemental Indenture dated as of February 1, 1973.
4-D-4 33-32499 4-D-7 --Thirty-Second Supplemental Indenture dated as of January 18, 1974.
4-D-5 2-66914 2-L-13 --Thirty-Ninth Supplemental Indenture dated as of October 15, 1979.
4-D-6 33-46070 4-D-11 --Forty-Second Supplemental Indenture dated as of December 1, 1990.
4-D-7 33-46070 4-D-12 --Forty-Third Supplemental Indenture dated as of February 1, 1991.
4-D-8 33-46070 4-D-13 --Forty-Fourth Supplemental Indenture dated as of September 1, 1991
4-D-9 8-K dated 4-D-15 --Forty-Fifth Supplemental 7/24/92 Indenture dated as of July 1, 1992
10-A 2-39794 4-C --Integrated Transmission Agreement dated August 25, 1967, between Cooperative Power Association and the Company.
10-A-1 10-K for year 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 --Amendment No. 4 dated 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.
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 --Supplement No. Six, dated 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 Owner- ship 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 Owner- ship 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 2-50382 5-F --Big Stone Plant Coal Agreement by and between the Company, Montana-Dakota Utilities Co., Northwestern Public Service Company, and Knife River Coal Mining Company (dated as of January 1, 1972).
10-G-1 10-Q for quarter 19-A --Amendment, dated as of ended 6/30/92 June 25, 1992, to Big Stone Plant Coal Agreement (dated as of January 1, 1972).
10-G-2 10-Q for quarter 19-A --Big Stone Coal Transportation ended 3/31/89 Agreement by and between the Company, Northwestern Public Service Company, Montana- Dakota Utilities Co. and Burlington Northern Railroad Company (dated as of October 5, 1983).
10-G-3 10-Q for quarter 19-A --Amendment No. 1, dated as of ended 6/30/90 May 30, 1990, to Big Stone Coal Transportation Agreement (dated as of October 5, 1983).
10-G-4 10-K for year 10-G-3 --Amendment No. 2, dated as of ended 12/31/91 February 4, 1991, to Big Stone Coal Transportation Agreement (dated as of October 5, 1983).
10-G-5 10-Q for quarter 19-D --Big Stone Plant Tire Derived ended 6/30/93 Fuel Agreement by and between the Company and BFI Tire Recyclers of Minnesota (dated as of November 2, 1992).
10-G-6 10-Q for quarter 19-E --Big Stone Plant Tire Derived ended 6/30/93 Fuel Agreement by and between the Company and National Tire Services (dated as of November 2, 1992).
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 Owner- ship 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 September 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).
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-J-1 10-K for year 10-J-1 --Mid-Continent Area Power Pool ended 12/31/92 Agreement dated March 31, 1972 (amended through May 1, 1985).
10-J-2 2-66914 5-J-1 --Memorandum of Understanding between Mid-Continent Area Power Pool Parties (dated as of December 1979).
10-K 10-K for year 10-K --Diversity Exchange Agreement ended 12/31/91 Agreement 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-K for year 10-K-2 --Firm Power Service Agreements ended 12/31/91 by and between Company and Manitoba Electric Hydro Board (dated as of January 27, 1992).
10-K-2 10-K for year 10-K-2 --Firm Power Service Agreement ended 12/31/92 by and between Company and Manitoba Electric Hydro Board (dated as of December 29,1992).
10-K-3 --Firm Power Service Agreements by and between Company and Manitoba Electric Hydro Board (dated as of February 8, 1994).
10-K-4 10-Q for quarter 19-B --Purchased Power and ended 6/30/92 Interconnection Agreement between the Company and Potlatch Corporation dated as of June 3, 1992.
10-K-5 10-K for year 10-K-4 --Capacity and Energy Agreement ended 12/31/92 by and between the Company and Minnkota Power Cooperative, Inc. dated as of May 4, 1992.
10-K-6 10-K for year 10-K-5 --Interchange Agreement by and ended 12/31/92 between the Company and Wisconsin Power and Light Company dated as of February 21, 1992.
10-K-7 10-K for year 10-K-6 --Interchange Agreement by and ended 12/31/92 between the Company and Wisconsin Electric Power Co. dated as of June 26, 1992.
10-K-8 10-K for year 10-K-7 --Firm Power Service Agreement ended 12/31/92 by and between the Company and Lincoln Electric System dated as of September 11, 1992.
10-K-9 10-Q for quarter 19-B --Interchange Agreement by and ended 6/30/93 between the Company and Wisconsin Public Service Corporation dated as of January 20, 1993.
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-1 10-K for year 10-M-1 --Hoot Lake Plant Coal ended 12/31/89 Agreement dated as of October 1, 1980, by and between the Company and Knife River Coal Mining Company.
10-M-2 10-K for year 10-M-2 --First Amendment dated as of ended 12/31/89 August 14, 1985, to Hoot Lake Plant Coal Agreement.
10-M-3 10-K for year 10-M-3 --Hoot Lake Coal Transporta- ended 12/31/89 tion Agreement dated as of September 2, 1988 by and between the Company and Burlington Northern Rail- road Company.
10-M-4 10-K for year 10-M-4 --Supplement One dated as of ended 12/31/89 December 16, 1988, to Hoot Lake Coal Transportation Agreement.
10-M-5 10-K for year 10-M-5 --Supplement Two dated as of ended 12/31/89 April 5, 1989, to Hoot Lake Coal Transportation Agreement.
10-M-6 10-K for year 10-M-6 --Supplement Three dated as ended 12/31/89 of December 18, 1989, to Hoot Lake Coal Transporta- tion Agreement.
10-M-7 10-K for year 10-M-7 --Supplement Four dated as of ended 12/31/91 May 10, 1991, to Hoot Lake Coal Transportation Agreement.
10-M-8 10-K for year 10-M-8 --Supplement Five dated as of ended 12/31/92 December 11, 1992 to Hoot Lake Coal Transportation Agreement.
10-M-9 10-K for year 10-M-9 --Supplement Six dated as of ended 12/31/92 January 11, 1993 to Hoot Lake Coal Transportation Agreement.
10-M-10 --Supplement Seven dated as of November 22, 1993 to Hoot Lake Coal Transportation Agreement.
10-M-11 10-K for year 10-M-10 --Hoot Lake Coal Transportation ended 12/31/92 Agreement dated January 15, 1993 by and between the Company and Northern Coal Transportation Co.
10-M-12 10-Q for quarter 19-C --First Amendment dated as of ended 6/30/93 January 20, 1993 to Hoot Lake Coal Transportation Agreement dated January 15, 1993.
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-O --Executive Survivor and Sup- ended 12/31/92 plemental Retirement Plan, as amended.*
10-N-3 10-K for year 10-P --Form of Severance Agreement.* ended 12/31/92
10-N-4 --Nonqualified Pension Plan*
10-N-5 --Nonqualified Profit Sharing Plan.*
10-N-6 --Nonqualified Retirement Savings Plan.*
10-O --Dealer Agreement by and between DMS and Philips Medical Systems North America Company dated January 18, 1994.
13-A --Portions of 1993 Annual Report to Shareholders incorporated by reference in this Form 10-K.
21-A --Subsidiaries of the Registrant
23-A --Independent Auditors' Consent.
24-A --Powers of Attorney.
- ------------ * Management contract or compensatory plan or arrangement required to be filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K.