-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Nkd+60c1XRO1+3AG/W2AEo5lek5ftAfFuQYWLHdPTmkXU4TBrxVLmdPR5pMSJ8gz qX1KeWWi1fRT5BuPWx8fyg== 0000075129-96-000009.txt : 19960329 0000075129-96-000009.hdr.sgml : 19960329 ACCESSION NUMBER: 0000075129-96-000009 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960328 SROS: NASD FILER: COMPANY DATA: COMPANY CONFORMED NAME: OTTER TAIL POWER CO CENTRAL INDEX KEY: 0000075129 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 410462685 STATE OF INCORPORATION: MN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-00368 FILM NUMBER: 96539614 BUSINESS ADDRESS: STREET 1: 215 S CASCADE ST STREET 2: PO BOX 496 CITY: FERGUS FALLS STATE: MN ZIP: 56538-0496 BUSINESS PHONE: 2187398200 10-K 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10 - K (Mark One) (X) Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (fee required) For the fiscal year ended December 31, 1995 OR ( ) Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (no fee required) For the transition period from _______to_______ Commission File Number 0-368 OTTER TAIL POWER COMPANY (Exact name of registrant as specified in its charter) MINNESOTA 41 -0462685 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 215 S. CASCADE ST., BOX 496, FERGUS FALLS, MN 56538-0496 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code:(218)739-8200 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered NONE NONE Securities registered pursuant to Section 12(g) of the Act: COMMON SHARES, par value $5.00 per share CUMULATIVE PREFERRED SHARES, without par value (Title of class) Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ( ) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. (Yes X No ) State the aggregate market value of the voting stock held by nonaffiliates of the registrant. $411,315,199 as of March 1, 1996 Indicate the number of shares outstanding of each of the registrant's classes of Common Stock, as of the latest practicable date: 11,180,136 Common Shares ($5 par value) as of March 1, 1996 Documents Incorporated by Reference: 1995 Annual Report to Shareholders-Portions incorporated by reference into Part II Proxy Statement dated March 8, 1996-Portions incorporated by reference into Part III PART I Item 1. BUSINESS (a) General Development of Business Otter Tail Power Company (the "Company") is an operating public utility 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, Manufacturing and Other Business Operations. Health Services Operations consists of certain businesses acquired beginning in 1993, including the 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. Manufacturing Operations includes businesses acquired beginning in 1990 in such areas as metal parts stamping and fabrication, agricultural equipment, and plastic pipe extrusion. Other Business Operations include businesses involved in such areas as electrical and telephone construction contracting, radio broadcasting, waste incinerating, and telephone/cable TV utility. The Company continues to investigate acquisitions of additional non- electric businesses and expects continued growth in this area. In February 1996, the Company's subsidiary, Mid-States Development, Inc. ("Mid-States"), acquired a Montana-based supplier of X-ray supplies and accessories. In February 1996, Mid-States entered into an agreement to acquire three radio stations in the Fargo, ND-Moorhead, MN market, subject to FCC approval. Also in February 1996, Mid-States entered into a letter of intent to acquire a mobile medical diagnostic services company located in Bemidji, Minnesota, subject to the negotiation of a definitive purchase agreement and other conditions to closing. In 1995, the total combined revenues for all these businesses was approximately $29,000,000. If consummated, the total acquisition price for all these businesses will be approximately $10,000,000. 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 1995 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, Health Services, Manufacturing, and Other Business 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 1995 Annual Report to Shareholders, filed as an Exhibit hereto. (c) Narrative Description of Business ELECTRIC OPERATIONS General The Company derived 62% of its consolidated operating revenues from the sale of electric energy during 1995; 69% during 1994; and 73% during 1993. During 1995 the Company derived approximately 55.4% of its electric revenues from Minnesota, 37.4% from North Dakota, and 7.2% 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, 52.2% of 1995 electric revenues was derived from commercial and industrial customers, 31.9% from residential customers, and 15.9% from other sources, including municipalities, farms and power pools. No customer accounted for more than 10% of electric revenues. Power pool sales to other utilities, which accounted for 25.3% of total 1995 kwh sales, decreased only slightly from 1994. Activity in short-term energy sales is subject to change based on a number of factors and the Company is unable to predict the 1996 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 1995 total customers had increased to 124,082. During 1995, the Company experienced a net increase of 859 customers, with the majority of growth in residential and commercial customers. Competition 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. 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 business. The 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. The NEPA prohibits retail wheeling ordered by the Federal Energy Regulatory Commission, but it does not address the states' authority to order retail wheeling. In 1995, the Federal Energy Regulatory Commission ("FERC") issued a Notice of Proposed Rulemaking ("NOPR") to promote competition and deregulation in wholesale electric markets by requiring owners of transmission facilities to offer nondiscriminatory open-access transmission and ancillary services to wholesale sellers and purchasers of electric energy in interstate commerce. This NOPR, referred to as the Mega-NOPR, requires the establishment of tariffs by all owners of transmission facilities for point to point and network transmission services, to which the owners of the facilities will also be subject. The NOPR also addresses the issue of recovery of stranded investment costs which may result when a utility's customer is lost to another supplier of electric energy. The FERC is currently receiving comments on the NOPR and final rules have not been issued. The FERC has not established tariffs for transmitting utilities. The Company has preliminarily determined that the NOPR, in its current form, would not likely result in the Company having any stranded investment costs due to the Company's competitively low generation costs. As the electric industry evolves, the Company may also have opportunities to increase its market share. The Company's generation capacity appears well positioned 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 would attempt more flexible pricing strategies under an open, competitive environment. Rate Matters The Company is subject to electric rate regulation as follows: Year Ended December 31, 1995 % of Electric % of kwh Rates Regulation Revenues Sales MN retail sales MN Public Utilities Commission 46.4% 39.7% ND retail sales ND Public Service Commission 36.8 29.1 SD retail sales SD Public Utilities Commission 7.1 5.6 Transmission & sales FERC for resale 9.7 25.6 _____ _____ 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, 1991: Increase (Decrease) Granted Commission Date Amount % (Thousands) Minnesota Last Proceeding was July 1, 1987 North Dakota (1)September 9, 1992 ($1,000) (1.5%) (2)September 22, 1993 ($ 449) (0.6%) South Dakota Last Proceeding was November 1, 1987 FERC Last Proceeding was July 1, 1987 In 1994 the Company filed a petition with the Minnesota Public Utilities Commission for approval of an annual recovery mechanism for demand-side management related costs, under Minnesota's Conservation Improvement Programs. See "General Regulation". An intervenor, on behalf of the Large General Service Group, filed comments against the petition and requested the Commission to order a general rate case to review the Company's earnings levels. In the interest of rate stability the Company reached an agreement, which was approved by the Commission, resulting in costs of approximately $2,200,000 each year for three years which must be absorbed in current rates starting in 1995. 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 __________ (1) 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. (2) An agreement for incentive regulation reached between the Company and the North Dakota Commission provided for sharing equally between ratepayers and shareholders any amount earned in 1993 over or under a benchmark overall rate of return. A liability of $449,000 resulting from sharing earnings above this benchmark for 1993 was returned to customers in 1994. 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 South Dakota Public Utilities 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. North Dakota law allows a forward test year. 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, 1995, the Company had base load net plant capability totaling 551,594 kw, consisting of 241,256 kw from the Big Stone Plant (the Company's 53.9% share), 155,800 kw from the Hoot Lake Plant, 149,450 kw from the Coyote Plant (the Company's 35% share), and under contract 5,088 kw from the Potlatch 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 90,968 kw, and 4,193 kw of hydroelectric capability. During 1995 the Company generated about 71% 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 exchange agreement with another utility for the annual exchange of 75,000 kw of seasonal diversity capacity which runs through 2004. In addition, for the 1995-1996 winter season, the Company has 50,000 kw capacity available for purchase from other utilities. The Company also has agreements to purchase 110,000 kw of capacity for the summer of 1996 and 50,000 kw of year-round capacity for the May 1, 1997 through April 30, 2005 period. 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, which includes 29 full participans, 30 associate participants, and 1 liaison participant representing investor-owned utilities, rural cooperatives, municipal utilities, and other power suppliers (including power marketers) 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 engage in power transactions with each other. The Company traditionally experiences its peak system demand during the winter season. For the calendar year 1995, the Company established a new system peak demand of 594,350 kw on December 11, 1995. The highest previous sixty-minute peak demand was 589,239 kw on January 8, 1993. Taking into account additional capacity available to it in December 1995 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 773,755 kw. In 1996 the Company expects moderate growth in peak demand as compared to 1995. 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 1996 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. Hoot Lake has burned primarily western subbituminous coal since 1988, and Big Stone switched from North Dakota lignite to western subbituminous coal in August of 1995. The following table shows for 1995 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 . . . . . . . . . . . . . 2,011,566 70.0% Subbituminous Coal . . . . . . . . . . 837,960 29.1 Hydro . . . . . . . . . . . . . . . . . 25,474 .9 Oil . . . . . . . . . . . . . . . . . . 1,219 - _________ _____ Total . . . . . . . . . . . . . . . 2,876,219 100.0% The Company has a coal supply agreement with Westmoreland Resources, Inc. of Billings, Montana, for supply of subbituminous coal to Big Stone Plant from mid-1995 through 1999. The coal comes from the Absaloka Mine near Hardin, Montana. The Company replaced the Big Stone Plant's coal stockpile in 1995 with subbituminous coal from Kennecott Energy's Spring Creek Mine. Big Stone's long-term lignite supply contract with Knife River Coal Mining Company ended in 1995. The Company has purchase agreements for fixed quantities of subbituminous coal with Kennecott Energy 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. Knife River Coal Mining Company is an affiliate of Montana-Dakota Utilities Co., which is a co-owner of the Big Stone and Coyote Plants. In November 1995 three of the four co-owners of the Coyote generating plant filed a summons and complaint against Knife River Coal Mining Company and MDU Resources Group, Inc. The three co-owners contend that the 14-year- old pricing mechanism outlined in the original coal supply contract has been abandoned by all parties over the past 7 years and no longer results in fair, equitable, and competitive prices for the lignite coal used to generate electricity at the plant. 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 coal used at Big Stone Plant is transported in coal cars belonging to the plant owners. The Company has entered into an agreement to acquire new aluminum coal cars for transporting coal to the Big Stone Plant beginning in September of 1996. The Company has a new coal transportation agreement with Burlington Northern Railroad for transportation services to the Big Stone Plant. This contract began in 1995 and runs through 1999. The new coal and freight agreements resulted in significantly lower delivered coal prices at the Big Stone Plant which will be returned to the Company's retail customers through the Cost of Energy Adjustment clause. Transportation costs of coal to Hoot Lake Plant are governed by tariffs established pursuant to authority of the Interstate Commerce Commission. The Company 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 the Hoot Lake Plant. That agreement was set to expire in January 1996, but is expected to be renewed for an additional three years. The Coyote Plant is a mine-mouth plant located in western North Dakota. There are no coal transportation costs, giving Coyote Plant the lowest delivered fuel costs as 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 1995, 1994, and 1993, was .969 cents, 100.3 cents and 100.7 cents, 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." The Company is permitted by the State of South Dakota to burn some alternative fuels, including tire and refuse derived fuel, at its Big Stone Plant. The quantity of alternative fuel burned during 1995, 2.3% of total fuel burned at the Big Stone Plant, and expected to be burned in 1996, is insignificant when compared to the coal consumption at the Big Stone Plant. 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, 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 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 a 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 belong to the property owner rather than the utility. In 1995 the MPUC approved an automatic recovery mechanism which allows the Company to begin collecting 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 jurisdictional utilities. The Company submitted its first plan in 1992, which was approved by the MPUC in 1993, and submitted its next plan in 1994, which was approved in 1995. 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 without the state) or any rate recovery therefrom, and shall 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. Whether these state policies are preempted by federal law has not been determined. 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 more than 115 kv. The Company is required to submit a ten-year plan to the North Dakota Commission annually. 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, 1995, approximately $8,900,000 for environmental control facilities (excluding allowance for funds used during construction). Included in the 1996-2000 construction budget are approximately $1,680,000 for environmental improvements for existing and new facilities, including $390,000 for 1996. 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 oxide ("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. The Company has a new subbituminous coal contract for Big Stone Plant which runs through December 1999. The subbituminous coal 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 sulfer subbituminous coal. The cost of subbituminous coal in 2000 and beyond may be higher than the current market price but would likely not adversely affect the Company's power plant operations. 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. 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 Company's Hoot Lake Plant units 2 and 3. The Act allows EPA to either retain the standard as it currently applies to phase one boilers or adopt more stringent standards for such phase two boilers by January 1, 1997. The Company has the option to either comply with the phase one standards beginning on January 1, 1997, under EPA's early opt-in provision, or comply with any revised standard for phase two units. If the Company elects the early opt-in provision, the Company would be governed by the standard until January 1, 2008. Subject to additional evaluation of the results of continuous emission monitoring which began at Hoot Lake in 1994, the Company anticipates that it will elect the early opt-in provision for Hoot Lake Plant unit 2 and may also do so for unit 3. The Company currently anticipates that the cost of complying with the limitations expected to be applicable to Hoot Lake Plant will not be material. On January 19, 1996, the EPA also proposed NOx emissions regulations that would be applicable to cyclone-fired boilers such as those used at Big Stone and Coyote. The Act requires the EPA to specify before January 1, 1997, the NOx limitations for cyclone boilers. If the regulations are adopted as proposed, modifications may be required at Big Stone by 2000 to satisfy the emission standards. Compliance costs will depend on the regulations that are ultimately adopted and the cost of available technologies. 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, 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 its Big Stone Plant. A water discharge permit for the Hoot Lake Plant was renewed in 1992 for a five-year term. A 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 3,398 kw at December 31, 1995). 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, 1995, 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 acquired beginning in 1993 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. The Company derived 15% of its consolidated operating revenues from this segment in 1995, 16% in 1994, and 12% 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, radiographic 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. In 1994 DMS 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 service companies 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, is engaged primarily in providing mobile CT and MRI services in the Upper Midwest, and also provides interim scanner rental 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 technologists 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 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. MANUFACTURING OPERATIONS General Manufacturing Operations consists of businesses involved in the production of agricultural equipment, plastic pipe extrusion, and metal parts stamping and fabrication. Initial acquisitions of businesses in this sector were made in 1990. Two additional companies were acquired in 1995, one in January and the other in October. The Company derived 12% of its consolidated operating revenues from this segment in 1995, 5% in 1994, and 3% in 1993. The following is a brief description of each of these businesses: Precision Machine of North Dakota, Inc., located in West Fargo, ND, uses computer numerically controlled lathes and milling machines to produce parts for manufacturers. Dakota Machine, Inc., located in West Fargo, ND, is primarily engaged in metal fabrication of large machines that handle and refine sugar beets. Dakota Engineering, Inc., a subsidiary of Dakota Machine, Inc., was formed in 1995 and is engaged in design engineering and construction management, primarily in the sugar industry. Glendale Machining, Inc., located in Pelican Rapids, MN, uses computer numerically controlled lathes and milling machines to produce parts for manufacturers. 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. Northern Pipe Products, Inc., located in Fargo, ND, manufactures poly- vinyl-chloride (PVC) pipe for municipal, rural water, irrigation and other uses in a sixteen-state area. Each of the subsidiaries described above under Health Services and Manufacturing Operations are owned by Mid-States Development, Inc., which is a wholly-owned subsidiary of Minnesota Dakota Generating Company ("MDG"). MDG is a wholly-owned subsidiary of the Company. OTHER BUSINESS OPERATIONS General The Company's Other Business Operations consists of businesses that are diversified in such areas as electrical and telephone contracting, radio broadcasting, waste incinerating, and telephone/cable TV utility. The Company derived 11% of its consolidated operating revenues from these diversified businesses during 1995, 10% in 1994, and 12% during 1993. The following is a brief description of each of these businesses: Moorhead Electric, Inc., located in Moorhead, MN, provides commercial and industrial wiring of large buildings, constructs and maintains telecommunications and power distribution systems, and installs computer network cable. Aerial Contractors, Inc., located in West Fargo, ND, constructs and maintains overhead and underground electric, telecommunications, and cable television lines. KFGO, Inc., located in Fargo, ND, operates an AM and FM commercial radio station. Western Minnesota Broadcasting Company, located in Morris, MN, operates an AM and FM commercial radio station. Quadrant Co. ("Quadrant") operates a municipal waste burning facility located in Perham, MN. Pursuant to agreements which will expire in September 1996, Quadrant receives a processing fee from five Minnesota counties for disposal of mixed waste. Under agreements (which expired in June 1995 and have been extended) with two industrial customers, Quadrant sells the steam generated from the incineration process. The Company has invested approximately $3.65 million in plant and equipment in Quadrant. Quadrant represented approximately $2.7 million in sales for 1995 and an insignificant contribution to consolidated operating income for the Company. Long-term extensions of the above contracts will be necessary to provide for recovery of the amount the Company has invested in Quadrant. See "Environmental Regulation" below. Midwest Information Systems, Inc.("MIS"), headquartered in Parkers Prairie, MN, owns two operating telephone companies serving over 4,000 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. Quadrant is a wholly-owned subsidiary of 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 utility 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 Other Business Operations is subject to competition, as well as the effects of general economic conditions, in their respective industries. 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 In recent years, facilities such as Quadrant that burn municipal solid waste have been subjected to increasing state and federal environmental regulation. The Minnesota Pollution Control Agency promulgated rules relating to ash in 1993 and air emissions in 1994. The EPA has proposed air emission regulations which, if adopted as proposed, will defer to state regulations. Quadrant currently is operating under an expired air emission permit with the permission of the Minnesota Pollution Control Agency and submitted its application for a new air emission permit in April of 1995. Historically the terms of Quadrant's contacts with customers have enabled Quadrant to pass on to its customers much of the cost of environmental compliance. The increasing cost of environmental compliance may adversely affect Quadrant's ability to successfully negotiate the renewal of the contracts discussed above. CONSTRUCTION PROGRAM & FINANCING The Company is continually expanding, replacing and improving its electric utility facilities. During 1995 the Company invested approximately $28,327,000 (including allowance for funds used during construction) for additions to its electric utility properties. During the five years ended December 31, 1995, the Company had gross electric property additions, including construction work in progress, of approximately $123,674,000 and gross retirements of approximately $30,260,000. During 1995 capital expenditures of approximately $4,000,000 were also made in both Health Services and Manufacturing, and $2,000,000 in Other Business Operations. Total capital expenditures for the Company and its subsidiaries during the five-year period 1996-2000 are estimated to be approximately $171,000,000. Of this $14,000,000 is for Health Services Operations, $9,000,000 for Manufacturing, and $7,000,000 for Other Business Operations. The Company estimates that during the five years 1996 through 2000 it will invest for electric utility construction approximately $141,000,000 (including allowance for funds used during construction). The Company continously 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 1996 through 2000 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 meet all sinking fund payments for First Mortgage Bonds in the next five years and to provide for the majority of its 1996-2000 construction program expenditures. Additional short-term or long-term financing will be required in the period 1996-2000 in connection with a portion of the Company's construction program, 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, 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, tax law changes, and rate regulation. As of December 31, 1995, the Company had unutilized net fundable property available for the issuance of more than $30,000,000 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 any subsidiary money or cosign on any of their borrowing. The Company has access to short-term borrowing resources. As of December 31, 1995, the Company and subsidiaries had unused credit lines totaling $42,600,000. The Company had no short-term borrowings as of December 31, 1995. However, the subsidiary companies had $7,200,000 of credit lines in use at December 31, 1995, a portion classified as current maturities and a portion classified as long-term debt depending on the terms and nature of use. EMPLOYEES The Company and its subsidiaries had approximately 1,552 full-time employees at December 31, 1995. A total of 476 employees are represented by local unions of the International Brotherhood of Electrical Workers, of which 432 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. 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, 1995, 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; 567 miles of 115 kv lines; and 4,270 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. LEGAL PROCEEDINGS Not Applicable. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the three months ended December 31, 1995. Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 1996) 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 (56) 4/8/91 Present: Chairman, President and Chief Executive Officer Prior to 4/8/91 President and Chief Executive Officer Andrew E. Anderson (56) 4/10/95 Present: Vice President, Finance Prior to 4/10/95 Controller Marlowe E. Johnson (51) 4/12/93 Present: Vice President, Customer Service, North Dakota Prior to 4/12/93 Division Manager, Jamestown Douglas L. Kjellerup (54) 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 (50) 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 (57) 1/1/78 Present: Vice President, Corporate Services Jay D. Myster (57) 4/12/82 Present: Vice President, Governmental and Legal, and Corporate Secretary Rodney C.H. Scheel (46) 4/10/95 Present: Vice President, Electrical Prior to 4/10/95 Director, Information Services Ward L. Uggerud (46) 4/10/89 Present: Vice President, Operations Jeffrey J. Legge(39) 4/10/95 Present: Controller Prior to 4/10/95 Manager, Tax Department Prior to 5/1/91 Manager, General Accounting 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. 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 the 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 1995 Annual Report to Shareholders, filed as an Exhibit hereto. Item 6. SELECTED FINANCIAL DATA The information required by this Item is incorporated by reference to "Selected consolidated financial data" on Page 23 of the Company's 1995 Annual Report to Shareholders, filed as an Exhibit hereto. Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information required by this Item is incorporated by reference to "Management's discussion and analysis of financial condition and results of operations" on Pages 24 through 31 of the Company's 1995 Annual Report to Shareholders, filed as an Exhibit hereto. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required by this Item is incorporated by reference to "Quarterly information" on Page 45 and the Company's audited financial statements on Pages 32 through 45 of the Company's 1995 Annual Report to Shareholders excluding "Report of Management" on Page 32, filed as an Exhibit hereto. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this Item is incorporated by reference from the information under "Nominees for Election as Directors" in the Company's definitive Proxy Statement dated March 8, 1996. The information regarding executive officers is set forth in Item 4A hereto. Item 11. EXECUTIVE COMPENSATION The information required by this Item is incorporated by reference from the information under "Summary Compensation Table", "Pension and Supplemental Retirement Plans", "Severance Agreements", and "Directors' Compensation" in the Company's definitive Proxy Statement dated March 8, 1996. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this Item is incorporated by reference from the information under "Outstanding Voting Shares" and "Security Ownership of Management" in the Company's definitive Proxy Statement dated March 8, 1996. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this Item is incorporated by reference from the information under "Nominees for Election as Directors" in the Company's definitive Proxy Statement dated March 8, 1996. PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) List of documents filed: (1) and (2) See Table of Contents on Page 22 hereof. (3) See Exhibit Index on Pages 23 through 31 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, 1995. 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/ A. E. Anderson A. E. Anderson Vice President, Finance Dated: March 27, 1996 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 ) ) A. E. Anderson ) Vice President, Finance ) (principal financial officer) ) ) Jeffrey J. Legge ) Controller ) By /s/ A. E. Anderson (principal accounting officer) ) A. E. Anderson ) Pro Se and Attorney-in-Fact ) Dated March 27, 1996 Thomas M. Brown, Director ) ) Dayle Dietz, Director ) ) Dennis R. Emmen, Director ) ) Maynard D. Helgaas, Director ) ) Arvid R. Liebe, Director ) ) Kenneth L. Nelson, Director ) ) Nathan I. Partain, Director ) ) Robert N. Spolum, Director ) OTTER TAIL POWER COMPANY TABLE OF CONTENTS FINANCIAL STATEMENTS, SUPPLEMENTARY FINANCIAL DATA, SUPPLEMENTAL FINANCIAL SCHEDULES INCLUDED IN ANNUAL REPORT (FORM 10-K) FOR THE YEAR ENDED DECEMBER 31, 1995 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, 1995: Page in Annual Report to Shareholders Financial Statements: Independent Auditors' Report. . . . . . . . . . . . . . . . . . . . . .33 Consolidated Balance Sheets, December 31, 1995 and 1994 . . . . . 32 & 33 Consolidated Statements of Income for the Three Years Ended December 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . .34 Consolidated Statements of Retained Earnings for the Three Years Ended December 31, 1995 . . . . . . . . . . . . . . . . . .34 Consolidated Statements of Cash Flows for the Three Years Ended December 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . .35 Consolidated Statements of Capitalization, December 31, 1995 and 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .36 Notes to Consolidated Financial Statements. . . . . . . . . . . . . 37-45 Selected Consolidated Financial Data for the Five Years Ended December 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . 23 Quarterly Data for the Two Years Ended December 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . .45 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. Exhibit Index to Annual Report on Form 10-K For Year Ended December 31, 1995 Previously Filed As Exhibit File No. No. 3-A 10-K for year 3-A --Restated Articles of ended 12/31/94 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 10-K for year 10-C-6 --Amendment No. 4 dated ended 12/31/93 January 18, 1994, to Supple- ment Seven. 10-D 2-55813 5-F --Contract dated April 12, 1973, between the Bureau of Reclamation and the Company. 10-E-1 2-55813 5-G --Contract dated January 8, 1973, between East River Electric Power Cooperative and the Company. 10-E-2 2-62815 5-E-1 --Supplement One dated February 20, 1978. 10-E-3 10-K for year 10-E-3 --Supplement Two dated ended 12/31/89 June 10, 1983. 10-E-4 10-K for year 10-E-4 --Supplement Three dated ended 12/31/90 June 6, 1985. 10-E-5 10-K for year 10-E-5 --Supplement No. Four, dated ended 12/31/92 as of September 10, 1986. 10-E-6 10-K for year 10-E-6 --Supplement No. Five, dated ended 12/31/92 as of January 7, 1993. 10-E-7 10-K for year 10-E-7 --Supplement No. Six, dated ended 12/31/93 as of December 2, 1993. 10-F 10-K for year 10-F --Agreement for Sharing ended 12/31/89 Ownership of Generating Plant by and between the Company, Montana-Dakota Utilities Co., and North- western Public Service Company (dated as of January 7, 1970). 10-F-1 10-K for year 10-F-1 --Letter of Intent for pur- ended 12/31/89 chase of share of Big Stone Plant from Northwestern Public Service Company (dated as of May 8, 1984). 10-F-2 10-K for year 10-F-2 --Supplemental Agreement No. 1 ended 12/31/91 to Agreement for Sharing Ownership of Big Stone Plant (dated as of July 1, 1983). 10-F-3 10-K for year 10-F-3 --Supplemental Agreement No. 2 ended 12/31/91 to Agreement for Sharing ownership of Big Stone Plant (dated as of March 1, 1985). 10-F-4 10-K for year 10-F-4 --Supplemental Agreement No. 3 ended 12/31/91 to Agreement for Sharing ownership of Big Stone Plant (dated as of March 31, 1986). 10-F-5 10-K for year 10-F-5 --Amendment I to Letter of ended 12/31/92 Intent dated May 8, 1984, for purchase of share of Big Stone Plant. 10-G 10-Q for quarter 10-A --Big Stone Plant Coal Agrmnt ended 9/30/94 by and between the Company, Montana-Dakota Utilities Co., Northwestern Public Service Company, and Westmoreland Resources, Inc. (dated as of June 30, 1994). 10-G-1 10-Q for quarter 10-B --Big Stone Coal Transp. ended 9/30/94 Agreement by and between the Company, Montana-Dakota Utilities, Northwestern Public Service Co., and Burlington Northern Railroad Company (dated as of July 18, 1994). 10-G-2 --Amendment No. 1, dated as of December 27, 1995, to Big Stone Coal Transportation Agreement (dated as of July 18, 1994).* 10-G-3 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-4 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 Ownership of Coyote Generating Unit No. 1 and Amendment No. 2 dated March 1, 1981, to Coyote Plant Coal Agreement. 10-H-3 10-K for year 10-H-3 --Amendment dated as of ended 12/31/89 July 29, 1983, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1. 10-H-4 10-K for year 10-H-4 --Agreement dated as of Sept. ended 12/31/92 5, 1985, containing Amendment No. 3 to Agreement for Sharing Ownership of Coyote Generating Unit No.1, dated as of July 1, 1977, and Amendment No. 5 to Coyote Plant Coal Agreement, dated as of January 1, 1978. 10-I 2-63744 5-I --Coyote Plant Coal Agreement by and between the Company, Minnkota Power Cooperative, Inc., Montana-Dakota Utilities Co., Northwestern Public Service Company, Minnesota Power & Light Company, and Knife River Coal Mining Company (dated as of January 1, 1978). 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 ended 12/31/92 Pool 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 by and between the Company and Northern States Power Company, (dated as of May 21, 1985) and amendment thereto (dated as of August 12, 1985). 10-K-1 10-Q for quarter 10 --Purchased Power and ended 6/30/94 Interconnection Agreement between the Company and Potlatch Corporation dated as of June 8, 1994. 10-K-2 10-K for year 10-K-4 --Capacity & Energy Agreement ended 12/31/94 by and between the Company and Minnkota Power Coop. Inc. dated as of May 27, 1994. 10-K-3 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-4 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-5 10-Q for quarter 19-B --Interchange Agreement by and ended 6/30/93 between the Company and Wisconsin Public Service Corp 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-10 --Hoot Lake Coal Transp. ended 12/31/92 Agreement dated January 15, 1993 by and between the Company and Northern Coal Transportation Co. 10-M-4 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-N-2 --Executive Survivor and Sup- ended 12/31/94 plemental Retirement Plan, as amended.** 10-N-3 10-K for year 10-P --Form of Severance Agrmnt.** ended 12/31/92 10-N-4 10-K for year 10-N-5 --Nonqualified Profit Sharing ended 12/31/93 Plan.** 10-N-5 10-K for year 10-N-6 --Nonqualified Retirement ended 12/31/93 Savings Plan.** 10-O 10-K for year 10-O --Dealer Agreement by and ended 12/31/93 between DMS and Philips Medical Systems North America Company dated January 18, 1994. 13-A --Portions of 1995 Annual Report to Shareholders incorporated by reference in this Form 10-K. 21-A --Subsidiaries of Registrant 23-A --Independent Auditors' Consent. 24-A --Powers of Attorney. 27 --Financial Data Schedule. - ------------ *Confidential information has been omitted from such Exhibit and filed separately with the Commission pursuant to a confidential treatment request under Rule 24b-2. ** Management contract or compensatory plan or arrangement required to be filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K. EX-10 2 Exhibit 10-G-2 Confidential information has been omitted from this Exhibit and filed separately with the Commission pursuant to a confidential treatment request under Rule 24b-2. FIRST AMENDMENT TO COAL TRANSPORTATION AGREEMENT ICC-BN-C-2913 This First Amendment to Coal Transportation Agreement ICC-BN-C-2913 (hereinafter referred to as "First Amendment") is made pursuant to 49 U.S.C. Section 10713 on this 27th day of December, 1995, by and among Burlington Northern Railroad Company, a Delaware corporation (hereinafter referred to as "BN"), Otter Tail Power Company, a Minnesota corporation, Northwestern Public Service Company, a Delaware corporation, and Montana- Dakota Utilities Co., a Division of MDU Resources Group, Inc., a Delaware corporation (hereinafter jointly referred to as "Utilities"). WHEREAS, BN and Utilities are parties to a Coal Transportation Agreement dated July 18, 1994, ICC-BN-C-2913 (hereinafter referred to as the "Original Agreement"); and WHEREAS, Utilities own and operate and electric generating plant described herein, known as the Big Stone Plant; and WHEREAS, BN and Utilities desire to amend the Original Agreement to provide for an allowance from coal transportation rates to the Big Stone Plant; such allowance arising from Utilities' proposed use of high capacity aluminum cars and BN's resulting provision of cars to supplement coal transportation requirements to the Big Stone Plant. NOW THEREFORE, in consideration of the premises, covenants, and considerations set out herein, the parties hereto agree as follows: Article I Filing, Approval, Effective Date, and Term of Amendment Section 1. Filing and Approval Within seven (7) days after its receipt of fully executed copies of this First Amendment, BN will file the requisite contract summary with the ICC in accordance with the provisions of 49 U.S.C. 10713 and the ICC regulations promulgated thereunder. Section 2. Effective Date and Term This First Amendment shall be effective on the date the contract summary is filed with the ICC (hereinafter "Effective Date"); PROVIDED, HOWEVER, that if the ICC disapproves this First Amendment, it will be null and void ab initio and any shipments moving on or between the date of filing of this First Amendment and the date of disapproval will be subject to the terms of the Original Agreement. In accordance with the agreement of the parties, subject to ICC approval of this First Amendment and the conditions of 49 C.F.R. 1313(c), the terms of this First Amendment shall apply on all trains of coal tendered on or after October 1, 1996. The term of this First Amendment shall end at 11:59 p.m. Central Standard Time on December 31, 1999. Confidential Contract Article II Modification of Transportation Rates Section 1. Modification of Effective Rates - Aluminum Cars Supplied by Utilities Commencing with the first train tendered as of the date noted earlier in Article I, Section 2, provided that Utilities have completed the installation of adequate railcar unloading facilities at the Big Stone Plant, and continuing through the term of this First Amendment as stated above, each of the then Effective Rates shall be reduced by $(*) per ton (the "Aluminum Car Allowance") which reflects the usage, by Utilities, of high capacity aluminum cars. The Aluminum Car Allowance shall apply to all tons tendered by Utilities for shipment in Utilities-supplied aluminum cars to the Big Stone Plant. The Aluminum Car Allowance shall not be adjusted during the term of the First Amendment. Section 2. Rates for Use of BN-Supplied Cars If Utilities elect to use BN-supplied cars, then commencing with the first train tendered as of the date noted earlier in Article I, Section 2, the rate for movement of coal from the Absaloka mine to the Big Stone Plant in BN-supplied cars shall be $(*) per ton. This rate shall be adjusted quarterly per Section 5 of the Original Agreement, with the first such adjustment to become effective on January 1, 1997. Article III General Nothing in this First Amendment shall alter the rights or obligations of the parties except as specifically set forth above. IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to Contract ICC-BN-C-2913 to be executed by their duly authorized representatives on the day and year first written above. OTTER TAIL POWER COMPANY By:/S/ Ward Uggerud Its: Vice President, Operations NORTHWESTERN PUBLIC SERVICE COMPANY By:/S/ A. R. Donnell Its: V.P. Energy Operations MONTANA-DAKOTA UTILITIES CO., a division of MDU Resources Group, Inc. By:/S/ Bruce Imsdahl Its: Vice President Energy Supply BURLINGTON NORTHERN RAILROAD COMPANY By:/S/ David S. Quilici Its: AVP Coal Marketing Confidential Contract Page 2 *Confidential information has been omitted and filed separately with the Commission pursuant to Rule 24b-2. EX-13 3 Exhibit 13-A DIVIDENDS We have paid quarterly dividends on our common stock since 1938 without interruption or reduction. 1995 dividends were $1.76 per share. The indicated annual rate for 1996 is $1.80. BUYING AND SELLING Otter Tail common stock is traded on NASDAQ's National Market System. (NASDAQ: National Association of Securities Dealers Automated Quotation.) Selected consolidated financial data - ---------------------------------------------------------------------------------------------------------- 1995 1994 1993 1992 1991 1990 1985 ---------- ---------- ---------- ---------- ---------- ---------- ---------- (Thousands except per-share data) Revenues Electric Residential $64,355 $62,687 $62,167 $59,038 $61,844 $60,326 $63,954 Commercial and farms 39,683 38,082 36,971 35,342 36,246 35,443 35,473 Industrial 69,756 69,332 65,757 63,522 62,284 58,812 57,442 Sales for resale 19,110 19,066 18,107 11,126 11,330 9,759 10,901 Other electric 11,021 9,645 9,288 8,077 7,752 7,999 7,684 ---------- ---------- ---------- ---------- ---------- ---------- ---------- Total electric $203,925 $198,812 $192,290 $177,105 $179,456 $172,339 $175,454 Health services 50,896 45,555 32,068 -- -- -- -- Manufacturing 38,690 13,083 8,473 -- -- -- -- Other business operations 35,130 30,073 32,396 32,433 20,389 8,009 -- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Total operating revenues $328,641 $287,523 $265,227 $209,538 $199,845 $180,348 $175,454 Net income $28,945 $28,475 $27,369 $26,538 $26,096 $24,852 $24,687 Cash flow from operations $58,077 $51,832 $53,255 $44,866 $46,667 $46,681 N/A Total assets $609,196 $578,972 $563,905 $530,456 $491,633 $477,224 $480,298 Long-term debt $168,261 $162,196 $166,563 $159,295 $146,326 $135,186 $150,902 Redeemable preferred $18,000 $18,000 $18,000 $18,000 $13,150 $13,705 $28,875 Common shares outstanding (1) (thousands) 11,180 11,180 11,180 11,180 11,185 11,223 11,955 Number of common shareholders (2) 13,933 14,115 13,634 13,812 13,928 13,984 16,661 Earnings per common share (3) $2.38 $2.34 $2.23 $2.17 $2.15 $1.99 $1.77 Dividends per common share $1.76 $1.72 $1.68 $1.64 $1.60 $1.56 $1.38 - ---------------------------------------------------------------------------------------------------------- Notes: (1) Number of shares outstanding at year-end. (2) Holders of record at year-end. (3) Based on average number of shares outstanding.
Management's discussion and analysis of financial condition and results of operations Management's major financial objective is to increase shareholder value by continuing to earn a reasonable return on the Company's capital. This will enable the Company to preserve and enhance its financial capability by maintaining acceptable capitalization ratios, maintaining a strong interest coverage position, providing a reasonable return to the common shareholder, maintaining an above average level of internal cash generation, and preserving and strengthening its current credit ratings on outstanding securities to the benefit of both the Company's customers and its shareholders. Liquidity: Liquidity is the ability to generate adequate amounts of cash to meet the Company's needs, both short-term and long-term. An electric utility's liquidity is a function of its construction program and debt service requirements, its net internal funds generation and its access to long-term securities markets and credit facilities for external capital. 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 any subsidiary money, or cosign on any of their borrowing. The Company has achieved a high degree of long-term liquidity by maintaining desired capitalization ratios and strong bond ratings, implementing cost- containment programs, evaluating operations and projects on a cost-benefit approach, investing in projects that enhance shareholder value, and obtaining adequate depreciation rates. Cash provided from operations, as indicated by the Consolidated Statement of Cash Flows for the year ended December 31, 1995, of $58,077,000, combined with net proceeds from the sale of marketable securities in 1995 of $17,043,000 and funds on hand of $2,243,000 at December 31, 1994, allowed the Company to pay dividends, invest in additional nonutility businesses and passive investments, finance its construction program, and retire First Mortgage Bonds through sinking fund operations. The Company estimates that funds internally generated combined with funds on hand will be sufficient to meet all sinking fund payments for First Mortgage Bonds in the next five years and to provide for the majority of its 1996-2000 construction program expenditures. (Internally generated funds consist of cash provided by operations less dividends and certain other adjustments.) Additional short-term or long-term financing will be required in the period 1996-2000 in connection with the following items: - A portion of the Company's construction program. - Maturity of First Mortgage Bonds and 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. - Other corporate purposes. The Company had $4.1 million in cash, cash equivalents and temporary cash investments at December 31, 1995, and $2.2 million at December 31, 1994. Capital Requirements: The Company has a construction and capital investment program to provide facilities necessary to meet forecasted customer demands and provide reliable service in the capital intensive electric utility business. This includes improvements to existing power plants, acquisition or construction of additional generating capacity, and upgrading or replacing portions of the distribution and transmission systems and other buildings and equipment. The construction program is subject to continuing review and is revised annually in light of changes in demands for energy, environmental laws, technology affecting the electric utility industry, the costs of labor, materials and equipment, and Company's financial condition (including cash flow and earnings). Capital project expenditures for the years 1995, 1994, and 1993 were $37 million, $30 million, and $31 million, respectively. The estimated capital expenditures for 1996 are $37 million, and the total expenditures for the five-year period 1996-2000 are expected to be approximately $171 million. The breakdown of 1995 actual and 1996-2000 estimated capital project expenditures by segment is as follows: 1995 1996 1996-2000 ---- ---- --------- (in millions) Electric utility $27 $32 $141 Health services 4 3 14 Manufacturing 4 1 9 Other business operations 2 1 7 In addition to these capital requirements, funds totaling approximately $63,217,000 will be needed during the five-year period 1996 through 2000 to retire First Mortgage Bonds and other long-term obligations, including subsidiary long-term obligations, at maturity and through sinking fund payments. Capital Resources: Financial flexibility is provided by unused lines of credit, financial coverages well in excess of the minimum levels required for issuance of securities, and strong credit ratings. As of December 31, 1995, unused credit lines totaling $42.6 million were available to meet interim financing of working capital and other capital requirements, if needed. The Company had no short-term borrowings as of December 31, 1995. However, the subsidiary companies had $7.2 million of credit lines in use at December 31, 1995, classified as current maturities and long-term debt. (See note 9 to financial statements for further information.) During 1995 the Company's coverage ratios remained at almost the same levels as in 1994. The fixed charge coverage ratio after taxes was 3.2 for 1995, as compared to 3.3 in 1994. The long-term debt interest coverage ratio before taxes was 4.3 for 1995, as compared to 4.5 in 1994. The Company expects these coverages to be approximately the same in 1996. The Company's credit ratings affect its access to the capital market. The current credit ratings for the Company's First Mortgage Bonds are as follows: Moody's Investors Service Aa3 Duff and Phelps AA Fitch Investors Service AA Standard and Poor's AA- The Company's disclosure of these security ratings is not a recommendation to buy, sell, or hold the Company's securities. As of December 31, 1995, the Company had the capacity under its Indenture of Mortgage to issue an additional $132 million principal amount of First Mortgage Bonds. Results of operations: Electric operations: Otter Tail Power Company provides electrical service to over 120,000 customers in a service territory of over 50,000 square miles. Operating Revenues - ------------------ The change in revenues may be summarized as follows: Revenue increase (decrease) from prior year ------------------------------ 1995 1994 1993 ---- ---- ---- (in thousands) Volume variance (1) $5,419 $6,979 $15,325 Price variance (2) (1,517) (492) (1,525) Other 1,211 35 1,385 ----- ----- ------ Total Electric $5,113 $6,522 $15,185 ===== ===== ====== (1) Derived for each customer class by multiplying year-to-year change in units sold by the average revenue per kwh for the prior year. (2) Derived for each customer class by multiplying the year-to-year change in average revenue per kwh by the units sold during the year. The 1995 volume variance was due to a 3.4% increase in retail kwh sales. The increase in retail kwh sales was due to increased sales in each customer class: residential, commercial, and industrial. Total power pool sales decreased by 1% from the previous year. Noncontractual power pool sales increased due to a combination of warmer weather and greater plant availability in 1995 which resulted in more opportunity sales. This increase was offset by a 53.7% decrease in contractual power pool sales. The 1994 volume variance was due to a 3.6% increase in retail kwh sales. The increase in retail kwh sales was principally due to increased sales to commercial and industrial customers. Power pool sales remained at the same level as in the previous year. Noncontractual power pool sales declined in 1994 because of the exceptionally high level of sales in 1993. However, contractual power pool sales were up significantly in 1994 because of a large sale to another utility. The 1993 volume variance was due to increased kwh sales in almost every retail customer classification and an 84% increase in noncontractual power pool sales. The increase in retail kwh sales can be attributed to the return of normal winter weather in 1993 coupled with increased usage in the commercial category. The increase in power pool sales can be attributed to the weather, which resulted in low water conditions in the spring in Manitoba and the widespread summer flooding in the Midwest. Heating degree days, which generally correlate to increases or decreases in usage by residential customers, were 9,326 for 1995, 9,204 for 1994, and 9,523 for 1993. The average revenue per retail kilowatt-hour was 5.45 cents in 1995, 5.50 cents in 1994, and 5.53 cents in 1993. The 1995 price variance was primarily attributed to residential and commercial sales, sales to a large industrial customer (See discussion under "Competition"), and the cost of energy adjustment clause. The negative variance in these categories was partially offset by a positive price variance in contractual power pool sales. The increase in contractual power pool sales revenue per kwh sold resulted from spreading a fixed demand charge over a decrease in kwh sales. The 1994 price variance was essentially due to industrial customers and contractual power pool sales. The decrease in contractual power pool sales revenue per kwh sold resulted from spreading a fixed demand charge over an increase in kwh sales. The 1993 price variance was primarily due to noncontractual power pool sales, residential sales, and the cost of energy adjustment clause. Noncontractual power pool sales had a 4.3% decrease in revenue per kwh sold in 1993. The price variance from residential sales was due to the increase in volume sold. In 1993 slightly over $7,100,000 (an increase of $350,000 over 1992) was returned to the Company's retail customers through the cost of energy adjustment clause. (See the explanation under "production fuel and purchased power expense.") The increase in the other variance in 1993 was due to the Company recognizing unbilled revenue of $1,446,000. The increase in other variance in 1995 reflects an increase in unbilled revenue of $388,000 over 1994 and the initial recognition of conservation program revenues and wheeling service fees in 1995. The Company changed its method of accounting in North Dakota from billing dates to energy delivery dates as a result of an order entered by the NDPSC in September 1993. The change in method of revenue recognition resulted in additional net income of $870,000 in 1993, $751,000 in 1994, and $984,000 in 1995. The impact on earnings per share was $.08 in 1993, $.07 in 1994 and $.09 in 1995. (See notes 1 and 3 to the financial statements for further information.) Expenses - -------- The percentage changes in operating expenses may be summarized as follows: Percentage increase (decrease) from prior year ------------------------------ 1995 1994 1993 ---- ---- ---- Production fuel (2) 3 10 Purchased power 7 5 22 Electric operation expenses 13 2 14 Electric maintenance (11) 6 18 Depreciation and amortization 3 4 4 Property taxes (6) 6 7 Production fuel and purchased power expense - ------------------------------------------- In 1995, the cost of steam production fuel per kwh generated decreased by 4.1% while the total kwhs generated increased by 1.6%, which, in combination, contributed to the 2% decrease in 1995 production fuel expense compared to 1994. The decrease in fuel cost per unit of generation resulted mainly from switching fuels at Big Stone plant from lignite to higher-Btu subbituminous coal in August of 1995. The 3% increase in production fuel in 1994 resulted chiefly from a 3.2% increase in generation. The 10% increase in production fuel in 1993 was due primarily to a 11% increase in generation. Of the increased generation, 56% was for power pool sales and 44% was for system use. The 7% increase in purchased power in 1995 was due to increased kwh purchases for system use, which correlates to the increase in retail sales. Purchased power increased 5% in 1994 essentially because of an increase in cost per kwh purchased. The bulk of the increase in cost per kwh purchased resulted from an increase in replacement generation cost for plant outages. The 22% increase in purchased power costs in 1993 was related directly to the increase in power pool sales. The increase or decrease in fuel and purchased power costs arising from changing prices results in adjustments to the Company's rate schedules through the cost of energy adjustment clause. Over the last five years, this has resulted in savings of slightly over $35 million to the Company's customers. Electric operation and maintenance expenses - ------------------------------------------- The increase in electric operating expense of 13% in 1995 was primarily due to two items: A settlement with the Minnesota Public Utilities Commission requiring recovery of Conservation Improvement Program costs in current rates starting in 1995 and an increase in postretirement health-care benefit costs resulting from a plan amendment which reduces the health insurance contribution requirements for surviving spouses of retired employees. (See notes 3 and 8 to financial statements for further information.) Storm-related expenses in the summer and fall of 1995 along with 1995 economic development expenditures and wage and salary increases also contributed to the increase in electric operating expense. The 1994 increase of 2% in electric operating expense resulted principally from increases in customer account expenses and payroll expenses. The increase of 14% in electric operation expense in 1993 was due primarily to increases in labor expenses (retiree medical benefits), North Dakota conservation programs, and administrative and general expenses. The 11% decrease in electric maintenance expense in 1995 was mainly due to significant reductions in power plant maintenance expenses. Coyote plant, which had a major overhaul in the spring of 1994 but no major overhauls in 1995, was the primary contributor to the reduction in maintenance expenses. Lower maintenance expenses on Hoot Lake Plant Unit #2, which underwent major repairs in the summer of 1994, also contributed to the decrease. The increase in electric maintenance expense of 6% in 1994 was due to increases in production and distribution maintenance. Production maintenance increased because of boiler repairs at the Coyote Plant. Distribution maintenance increased due to more tree-trimming expenses. The 18% increase in electric maintenance in 1993 was due to an increase in production maintenance of the steam plants (generator, turbine, and coal- handling equipment). Depreciation and amortization - ----------------------------- The increases in depreciation expense of 3% in 1995 and 4% in 1994 were attributable to additional plant in service in each of the respective years. The 4% increase in depreciation expense in 1993 was due to additional plant in service and higher depreciation rates. Property taxes - -------------- The 6% decrease in property taxes in 1995 was mainly due to decreased property tax rates in Minnesota and valuation decreases in South Dakota. The increases in property taxes of 6% for 1994 and 7% for 1993 were due to property additions and increased mill rates. Health services operations: Health services operations consist of businesses acquired by the Company, beginning in 1993, 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, primarily in the Midwest. 1995 1994 1993 ---- ---- ---- (in thousands) Operating revenues $50,896 $45,555 $32,068 Cost of goods sold 31,576 28,690 19,019 Operating expenses 15,739 14,379 10,781 ------- ------- ------- Pretax operating income $ 3,581 $ 2,486 $ 2,268 ======= ======= ======= The 12% increase in health services operating revenues in 1995 was due to increased sales of medical equipment in 1995 compared to 1994. The acquisition of three additional diagnostic imaging companies in January of 1995 also contributed to the increase in operating revenues. The increase in cost of goods sold in 1995 compared to 1994 was directly related to the 1995 increase in equipment sales. The increase in health services operating income in 1994 was due to an increase in sales of refurbished equipment as well as the results of a new subsidiary that was acquired by the Company toward the end of the first quarter of 1993. Manufacturing operations: Manufacturing operations is made up of businesses involved in the production of agricultural equipment, plastic pipe extrusion, and metal parts stamping and fabrication. Initial acquisitions of businesses in this sector were made in 1990. Two additional companies were acquired in 1995, one in January and the other in October. 1995 1994 1993 ---- ---- ---- (in thousands) Operating revenues $38,690 $13,083 $8,473 Cost of goods sold 29,884 9,167 6,175 Operating expenses 5,536 1,475 1,249 ------- ------- ------ Pretax operating income $ 3,270 $ 2,441 $1,049 ======= ======= ====== The increases in 1995 operating revenues and 1995 cost of goods sold and operating expenses resulted principally from the acquisition of two manufacturing companies in 1995 and sales in expanded product lines of companies acquired prior to 1995. The 54% increase in 1994 operating revenues, 48% increase in 1994 cost of goods sold, and 18% increase in 1994 operating expenses were mainly the result of increased sales of existing product lines. Other business operations: The Company's other business operations include a telephone utility and businesses involved in electrical and telephone construction contracting, radio broadcasting, and waste incinerating. 1995 1994 1993 ---- ---- ---- (in thousands) Operating revenues $35,130 $30,073 $32,396 Cost of goods sold 18,954 16,903 20,028 Operating expenses 11,152 9,779 8,813 ------- ------- ------- Pretax operating income $ 5,024 $ 3,391 $ 3,555 ======= ======= ======= Operating revenues increased by 17% in 1995, of which half was attributable to increased construction revenues related to material cost billings on large projects with a commensurate increase in cost of goods sold. The remaining increases in revenues and pretax operating income were due to modest contributions from all other businesses and an increase in miscellaneous income from the sale of salvaged materials in 1995. The decrease of 7% in operating revenues for 1994 reflects reductions in construction revenue offset by increases in radio broadcasting revenues. The 16% decrease in costs of goods sold in 1994 was due to decreased construction activity while the 11% increase in 1994 operating expenses resulted mainly from increased administrative and general and sales expenses in the radio broadcasting businesses, one of which was acquired in 1994. The administrative and general expenses at the construction companies remained about the same from 1993 to 1994. Consolidated income taxes: The 4% increase in 1995 income tax expense was related to an increase in pretax operating income. Income tax expense increased 11% in 1994 due primarily to higher pretax operating income. The 2% increase in income tax expense for 1993 was due to an increase in taxable income and higher corporate tax rates imposed by the Omnibus Budget Reconciliation Act of 1993. Consolidated interest charges: Interest charges increased 11% in 1995 and 5% in 1993 due to the new businesses acquired. Interest charges decreased in 1994 by less than 1%. Impact of inflation: For an electric utility, the regulatory process limits the amount of depreciation expense included in the Company's revenue allowance and limits electric utility plant in the rate base to original cost. Such amounts produce cash flows that are inadequate to replace such property in the future or preserve the purchasing power of common equity capital previously invested. Under continuation of the current regulatory process, the Company expects that it will be able to establish rates that will cover the increased costs of new plant when such costs are incurred. The Company operates under regulatory provisions that allow price increases in the cost of fuel and purchased power to be passed to customers through automatic adjustments to its rate schedules under the cost of energy adjustment clause. For the past seven years this has resulted in lower retail electric rates. Other increases in the cost of electric service must be recovered through timely filings for rate relief with the appropriate regulatory agency. The Company's health services, manufacturing and other business operations consist almost entirely of unregulated businesses. Increased operating costs are reflected in product or services pricing with any limitations on price increases determined by the marketplace. Factors affecting future earnings: Growth of electric revenue - -------------------------- The results of operations discussed above are not necessarily indicative of future earnings. Anticipated higher operating costs and carrying charges on increased investment in plant, if not offset by proportionate increases in operating revenues and other income (either by appropriate rate increases, increases in unit sales, or increases in nonelectric operations), will affect future earnings. Growth in electric sales will be subject to a number of factors, including the volume of power pool sales to other utilities, the effectiveness of demand-side management programs, weather, competition, and the rate of economic growth or decline in the Company's service area. The Company's electric business is primarily dependent upon the use of electricity by customers in our service area. Percentage changes in the Company's electric kwh sales to retail customers over the prior year for the last three years were an increase of 3.4% in 1995, an increase of 3.6% in 1994, and an increase of 5.0% in 1993. Rates of return earned on utility operations are subject to review by the various state commissions that have jurisdiction over the electric rates charged by the Company. These reviews may result in future revenue reductions when actual rates of return are deemed by regulators to be in excess of allowed rates of return. Demand-side management - ---------------------- Demand-side management (DSM) efforts will continue in all the jurisdictions that the Company serves. The goal of DSM is to encourage the wise and efficient use of electricity by customers. Successful DSM will contribute to the more efficient and cost-effective operation of existing and future generation and distribution facilities. Currently, Minnesota is the only jurisdiction that mandates investments in DSM, and indications are that the Minnesota Public Utilities Commission's (MPUC) emphasis in this area will continue into the foreseeable future. In 1994, the Company filed a petition with the MPUC for approval of an annual recovery mechanism for DSM-related costs under Minnesota's Conservation Improvement Programs (CIP). An intervenor on behalf of the Large General Service Group filed comments against the petition and requested the MPUC to order a general rate case to review the Company's earnings levels. In the interest of rate stability the Company reached an agreement, which was approved by the MPUC, resulting in costs to the Company of approximately $2.2 million each year for three years being absorbed in current rates starting in 1995. In 1995, the MPUC approved a .5030% surcharge on all Minnesota customers' bills starting on July 1, 1995, for the recovery of conservation-related costs over and above those being recovered in current rates. The approval of the surcharge resulted in increased earnings of approximately $620,000 in 1995 due to recognition of revenue related to CIP impacts on 1994 and 1995 energy consumption. The current surcharge rate will be in place until June 30, 1996, when it will be revised for subsequent years' program results. Energy adjustment clause - ------------------------ The Company began purchasing subbituminous coal for Big Stone Plant in August of 1995 under a new coal contract that will run through December 1999. Price reductions, in addition to plant efficiency gains due to switching from lignite to higher-Btu subbituminous coal, are estimated to result in cost reductions of about $4.9 million a year. The majority of these price reductions have been and will continue to be passed on to retail electric customers through the cost of energy adjustment clause, which enhances the Company's competitive position. In November of 1995 the Company and two other Coyote Plant partners initiated a lawsuit against Knife River Coal Mining Company and its parent, MDU Resources Group, in an attempt to resolve disputes over the pricing mechanism included in the Coyote coal agreement. Any adjustments to Coyote coal costs resulting from actions taken with regard to this lawsuit will be passed on to customers through the cost of energy adjustment clause. Environmental regulation - ------------------------ Under current regulations the Federal Clean Air Act (the Act) is not expected to have a significant impact on future capital requirements or operating costs. However, proposed or future regulations under the Act, changes in the future coal supply market, and/or other laws and regulations could impact such requirements or costs. It is anticipated that, under current regulatory principles, any such costs could be recovered through rates. The Company's plants are not subject to the Act's phase one requirements. Phase two standards of the Act must be met by the year 2000. The Company intends that the Big Stone Plant will maintain current levels of operation and meet phase two requirements for sulfur dioxide emissions by burning subbituminous coal, which is much lower in sulfur emissions than lignite. As stated previously, the Big Stone Plant's new coal contract expires at the end of 1999. The cost of subbituminous coal in 2000 and beyond will probably be higher than current market price but will likely not adversely affect the Company's power plant operations. Under recently proposed regulations, modifications would be required at Big Stone Plant by 2000 to satisfy proposed nitrogen oxide emission standards. Compliance costs will depend on the regulations that are ultimately adopted and the cost of available technologies. The Company's Coyote Plant is equipped with sulfur dioxide removal equipment. Compliance with the phase two requirements is not expected to significantly impact operations at that plant. The Hoot Lake Plant already uses low-sulfur subbituminous coal. Minor modifications may be required at the Hoot Lake Plant to meet the phase two nitrogen oxide emission requirements by 2000. Competition - ----------- The electric industry is becoming more competitive. Proposals for restructuring are being considered by various states and at the federal level. These proposals, along with the National Energy Policy Act of 1992 (NEPA), are expected to create more competition in the electric industry. The NEPA reduces restrictions on operation and ownership of independent power producers (IPP's). It also allows IPP's and other wholesale suppliers and purchasers increased access to transmission lines. The NEPA prohibits FERC-ordered retail wheeling, but it does not address the states' authority to order retail wheeling. In 1995 the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) to promote competition and deregulation in wholesale electric markets by requiring owners of transmission facilities to offer nondiscriminatory open-access transmission and ancillary services to wholesale sellers and purchasers of electric energy in interstate commerce. This NOPR, referred to as the Mega-NOPR, requires the establishment of tariffs by all owners of transmission facilities for point-to- point and network transmission services, to which the owners of the facilities will also be subject. The NOPR also addresses the issue of recovery of stranded investment costs that may result when a utility's customer is lost to another wholesaler of electric energy. The FERC is currently receiving comments on the NOPR, and final rules have not been issued. The FERC has not established tariffs for transmitting utilities. The Company has preliminarily determined that the proposal, in its current form, would not likely result in its having any stranded investment costs due to its competitively low generation costs. As the electric industry evolves, the Company may be subject to increased competition. However, the Company may also have opportunities to increase its market share. The Company's generation capacity appears well positioned 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 its rates are competitive. In addition, the Company would attempt more flexible pricing strategies under an open competitive environment. One of the Company's largest industrial customers set a goal of reducing its electric energy costs up to 25% by changing its consumption patterns and implementing more efficient processes requiring less energy. The Company worked with the customer toward achieving its goal by developing a new rate structure under a five year contract, with provisions for extension beyond five years, pending approval by the MPUC. If approved, the estimated impact on future revenue will be a decrease of $1.5 million annually. The Company anticipates that a portion of the decrease will be recovered through increased energy consumption by the customer, during certain periods, as a result of the new rate structure. Diversification - --------------- The Company continues to investigate acquisitions of additional businesses (both utility and nonutility) and expects continued growth in this area. The success of these businesses and any future business purchases will affect future earnings. The Company has invested approximately $3.65 million in net plant and equipment for its Quadrant subsidiary that sells steam to two industrial customers. Steam is produced by burning garbage at a fee from several counties. Although the original term of the contracts with the industrial customers expired in June 1995, Quadrant Co. continues to sell steam to both customers. The contract with one steam customer remains in effect until terminated by either party upon one year's prior written notice. Steam service to the other customer can be discontinued upon thirty days' notice by either party. As of December 31, 1995, none of the parties had provided notice of termination. In addition, the contracts for burning garbage will expire in September 1996. Quadrant represented approximately $2.7 million in sales for 1995 and contributed $93,000 to the Company's 1995 consolidated net income. In 1997, new pollution rules will be in effect that may require new operating permits and possible modifications to Quadrant's current plant operations and equipment. The costs to comply with the new pollution rules will have an impact on the negotiation of new waste incineration agreements and could affect the economic viability of the plant. Negotiations with Quadrant's incineration customers are currently underway to establish terms for continued service under long-term contracts. The contracts will allow for early termination if the implementation of new pollution rules is economically prohibitive. Successful negotiation of the above contracts will be necessary to provide for recovery of the amount the Company has invested in Quadrant. The amount of any losses from discontinuing operations cannot be accurately determined at this time. Accounting pronouncements - ------------------------- In 1994, the Company adopted SFAS 112 - Employer's Accounting for Postemployment Benefits - and SFAS 115 - Accounting for Certain Investments in Debt and Equity Securities. The adoption of SFAS 112 in 1994 did not have a material impact on the Company's financial statements. At December 31, 1994, as the result of adopting SFAS 115, the Company's marketable securities, which were principally invested in preferred stocks of other utilities, were recorded at fair value, which was $1,100,000 ($684,000 net of tax) less than original cost. The unrealized loss was recorded net of tax in shareholder's equity. The reduction in market value is because the investments reacted adversely to the increase in general interest rates during 1994. The Company's investment in these securities was completely liquidated in the fourth quarter of 1995 to provide for current cash needs. (See note 10 to the financial statements for further information.) In March of 1995 the Financial Accounting Standards Board issued SFAS 121 - Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, which will be effective for financial statements for fiscal years beginning after December 15, 1995. The statement requires that long-lived assets and certain identifiable intangibles to be held and used by an entity be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The statement also requires that a rate-regulated enterprise recognize an impairment for the amount of costs excluded when a regulator excludes all or part of a cost from the enterprise's rate base. The nature of utility regulation generally provides for the recovery of amounts invested in utility assets used to serve customers, over a specified period of time, through approved service rates and allowed rates of return on rate base. Currently, most of the Company's utility revenues are subject to regulation. The Company has determined that the carrying amounts of all its long-lived assets and identifiable intangibles at December 31, 1995, for both its utility and subsidiary operations are recoverable through expected future cash flows from the use of those assets, except in the case of its $3.65 million investment in Quadrant's net plant. An impairment amount for Quadrant cannot be determined at this time because of the uncertainty Quadrant has regarding its two industrial customer contracts and the new pollution rules scheduled for 1997 as previously discussed under "Diversification." In October of 1995, the Financial Accounting Standards Board issued SFAS 123 - - Accounting for Stock-Based Compensation, which will be effective for financial statements for fiscal years beginning after December 15, 1995. The statement establishes financial accounting and reporting standards for stock-based employee compensation. As of December 31, 1995, the Company had no stock-based employee compensation programs in place. Otter Tail Power Company Consolidated Balance Sheets, December 31 1995 1994 - ---------------------------------------------------------------------------------------- (in thousands) Assets Plant: Electric plant in service $715,305 $698,437 Other nonelectric plant 54,266 36,221 ---------- ---------- Total 769,571 734,658 Less accumulated depreciation and amortization 308,174 287,902 ---------- ---------- 461,397 446,756 Construction work in progress 16,285 10,485 ---------- ---------- Net plant 477,682 457,241 ---------- ---------- Investments 12,716 22,933 ---------- ---------- Intangibles--net 18,902 15,480 ---------- ---------- Other assets 7,732 5,531 ---------- ---------- Current assets: Cash and cash equivalents 1,867 1,852 Temporary cash investments 2,208 391 Accounts receivable: Trade (less accumulated provision for uncollectible accounts: 1995, $398,000; 1994, $432,000) 31,184 27,004 Other 8,276 5,172 Materials and supplies: Fuel 3,322 3,664 Inventory, materials and operating supplies 19,408 15,794 Deferred income taxes 3,754 4,306 Accrued utility revenues 4,328 4,154 Other 4,427 3,041 ---------- ---------- Total current assets 78,774 65,378 ---------- ---------- Deferred debits: Unamortized debt expense and reacquisition premiums 4,687 5,174 Regulatory assets 5,727 5,660 Other 2,976 1,575 ---------- ---------- Total deferred debits 13,390 12,409 ---------- ---------- Total $609,196 $578,972 ========== ========== See accompanying notes to consolidated financial statements. - ----------------------------------------------------------------------------------------
Otter Tail Power Company Consolidated Balance Sheets, December 31 1995 1994 - ---------------------------------------------------------------------------------------- (in thousands) Liabilities Capitalization (page 36): Common shares, par value $5 per share -- authorized, 25,000,000 shares; outstanding, 1995 and 1994 -- 11,180,136 shares $55,901 $55,901 Premium on common shares 30,335 30,335 Retained earnings 98,006 90,412 ---------- ---------- Total 184,242 176,648 Cumulative preferred shares: Subject to mandatory redemption 18,000 18,000 Other 20,831 20,831 Long-term debt 168,261 162,196 ---------- ---------- Total capitalization 391,334 377,675 ---------- ---------- Current liabilities: Short-term debt -- 2,900 Sinking fund requirements and current maturities 13,733 8,739 Accounts payable 27,828 22,542 Accrued salaries and wages 3,703 3,889 Federal and state income taxes accrued 393 2,095 Other taxes accrued 11,356 11,712 Interest accrued 3,509 3,524 Other 6,752 2,480 ---------- ---------- Total current liabilities 67,274 57,881 ---------- ---------- Noncurrent liabilities 13,498 8,245 ---------- ---------- Commitments (note 6) -- -- ---------- ---------- Deferred credits: Accumulated deferred income taxes 99,398 94,911 Accumulated deferred investment tax credit 20,994 22,171 Regulatory liabilities 14,500 15,197 Other 2,198 2,892 ---------- ---------- Total deferred credits 137,090 135,171 ---------- ---------- Total $609,196 $578,972 ========== ========== See accompanying notes to consolidated financial statements. - ----------------------------------------------------------------------------------------
Otter Tail Power Company Consolidated Statements of Income For the Years Ended December 31 1995 1994 1993 - -------------------------------------------------------------------------------------------- (in thousands) Operating revenues: Electric $203,925 $198,812 $192,290 Health services 50,896 45,555 32,068 Manufacturing 38,690 13,083 8,473 Other business operations 35,130 30,073 32,396 ---------- ---------- ---------- Total operating revenues 328,641 287,523 265,227 ---------- ---------- ---------- Operating expenses: Production fuel 31,559 32,311 31,325 Purchased power 30,591 28,717 27,438 Electric operation expenses 51,513 45,684 44,593 Electric maintenance 12,264 13,725 12,914 Cost of goods sold 80,414 54,760 45,222 Other nonelectric expenses 29,930 23,374 18,509 Depreciation and amortization 21,909 21,190 20,512 Property taxes 10,670 11,318 10,728 Income taxes 16,584 15,931 14,331 ---------- ---------- ---------- Total operating expenses 285,434 247,010 225,572 ---------- ---------- ---------- Operating income 43,207 40,513 39,655 ---------- ---------- ---------- Other income and deductions: Allowance for equity (other) funds used during construction 229 146 120 Other income and deductions and applicable taxes 584 1,503 1,419 ---------- ---------- ---------- Total other income and deductions 813 1,649 1,539 ---------- ---------- ---------- Income before interest charges 44,020 42,162 41,194 ---------- ---------- ---------- Interest charges: Interest 15,223 13,749 13,881 Allowance for borrowed funds used during construction--credit (148) (62) (56) ---------- ---------- ---------- Interest charges---net 15,075 13,687 13,825 ---------- ---------- ---------- Net income 28,945 28,475 27,369 Preferred dividend requirements 2,358 2,358 2,477 ---------- ---------- ---------- Earnings available for common shares $26,587 $26,117 $24,892 ========== ========== ========== Average number of common shares outstanding 11,180 11,180 11,180 Earnings per average common share $2.38 $2.34 $2.23 Dividends per common share $1.76 $1.72 $1.68 See accompanying notes to consolidated financial statements. Consolidated Statements of Retained Earnings For the Years Ended December 31 1995 1994 1993 - -------------------------------------------------------------------------------------------- (in thousands) Retained earnings at beginning of year $90,412 $84,209 $78,189 Net income 28,945 28,475 27,369 Other 684 (684) (80) ---------- ---------- ---------- Total 120,041 112,000 105,478 ---------- ---------- ---------- Dividends paid: Cumulative preferred shares at required annual rates 2,358 2,358 2,486 Common shares 19,677 19,230 18,783 ---------- ---------- ---------- Total 22,035 21,588 21,269 ---------- ---------- ---------- Retained earnings at end of year $98,006 $90,412 $84,209 ========== ========== ========== See accompanying notes to consolidated financial statements.
Otter Tail Power Company Consolidated Statements of Cash Flows For the Years Ended December 31 1995 1994 1993 - -------------------------------------------------------------------------------------------------- (in thousands) Cash flows from operating activities: Net income $28,945 $28,475 $27,369 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 28,602 25,899 25,348 Deferred investment tax credit--net (1,177) (1,347) (1,234) Deferred income taxes 751 1,386 3,937 Change in deferred debits and other assets (1,792) (1,016) (1,996) (Gain)/loss on disposal of noncurrent assets 946 (201) (77) Change in noncurrent liabilities and deferred credits 4,560 1,016 5,509 Allowance for equity (other) funds used during construction (229) (146) (120) Cash provided by (used for) current assets and current liabilities: Change in receivables, materials, and supplies (1,035) (10,712) (227) Change in other current assets (1,349) (339) (4,519) Change in payables and other current liabilities 1,436 6,720 250 Change in interest and income taxes payable (1,581) 2,097 (985) ---------- ---------- ---------- Net cash provided by operating activities 58,077 51,832 53,255 ---------- ---------- ---------- Cash flows from investing activities: Gross capital expenditures (37,134) (30,411) (30,894) Proceeds from disposal of noncurrent assets 2,417 2,574 1,574 Purchase of subsidiaries, net of cash acquired (5,808) (286) (4,056) Change in temporary cash investments (1,817) 60 9,204 Change in marketable securities and other investments 13,151 (1,630) (7,329) ---------- ---------- ---------- Net cash used in investing activities (29,191) (29,693) (31,501) ---------- ---------- ---------- Cash flows from financing activities: Change in short-term debt---net issuances (2,900) 2,900 -- Proceeds from issuance of long-term debt 54,482 6,433 33,156 Proceeds from issuance of preferred stock -- -- 4,000 Payments for debt and preferred stock issuance expense -- (56) (245) Payments for retirement of long-term debt (58,418) (11,784) (24,432) Payments to trustee for retirement of long-term debt -- -- (13,445) Payments for retirement of preferred stock -- -- (4,080) Dividends paid (22,035) (21,588) (21,269) ---------- ---------- ---------- Net cash used in financing activities (28,871) (24,095) (26,315) ---------- ---------- ---------- Net change in cash and cash equivalents 15 (1,956) (4,561) Cash and cash equivalents at beginning of year 1,852 3,808 8,369 ---------- ---------- ---------- Cash and cash equivalents at end of year $1,867 $1,852 $3,808 ========== ========== ========== Supplemental disclosures of cash flow information: Cash paid during the year for: Interest (net of amount capitalized) $14,160 $13,160 $13,371 Income taxes $18,286 $14,058 $12,009 See accompanying notes to consolidated financial statements.
Otter Tail Power Company Consolidated Statements of Capitalization, December 31 1995 1994 - ---------------------------------------------------------------------------------------- (in thousands) Total common shareholders' equity $184,242 $176,648 ---------- ---------- Cumulative preferred shares -- without par value (stated and liquidating value $100 a share) -- authorized 1,500,000 shares; outstanding: Series subject to mandatory redemption $6.35, 180,000 shares; 9,000 shares due 2002-06; 135,000 Shares due 2007 18,000 18,000 ---------- ---------- Total 18,000 18,000 Less current sinking fund requirement -- -- ---------- ---------- Total preferred subject to mandatory redemption 18,000 18,000 ---------- ---------- Other series: $3.60, 60,000 shares 6,000 6,000 $4.40, 25,000 shares 2,500 2,500 $4.65, 30,000 shares 3,000 3,000 $6.75, 40,000 shares 4,000 4,000 $9.00, 53,311 shares 5,331 5,331 ---------- ---------- Total other preferred 20,831 20,831 ---------- ---------- Cumulative preference shares -- without par value, authorized 1,000,000 shares; outstanding: none Long-term debt: First mortgage bond series: 8.75%, due December 15, 1997 19,000 19,200 7.25%, due August 1, 2002 19,400 19,600 7.625%, due February 1, 2003 9,360 9,480 8.75%, due September 15, 2021 19,200 19,400 8.25%, due August 1, 2022 29,100 29,400 Pollution control and industrial development series: 6.00-6.80%, due February 1, 2006, Big Stone project 5,487 5,547 8.125%, due August 1, 2009, Coyote project, series B 840 850 6.00-6.90%, due February 1, 2019, Coyote project 21,969 22,204 ---------- ---------- Total 124,356 125,681 Subsidiary and other long-term debt: Long-term lease obligation (5.625% pollution control revenue bonds due July 1, 1998) 2,200 2,200 Industrial development refunding revenue bonds 5.00% due December 1, 2002 3,010 3,010 Pollution control refunding revenue bonds variable 5.20% at December 31, 1995, due December 1, 2012 10,400 10,400 Industrial development revenue bond (Quadrant Co. project variable 5.36% at December 31, 1995, due April 1, 1996 -- Otter Tail Power Company guarantor) 200 600 Obligations of Mid-States Development, Inc. rates 3.89% to 10% at December 31, 1995 33,496 19,729 Obligations of North Central Utilities, Inc. variable 7.31% to 7.46% at December 31, 1995 9,013 9,999 Other 8 49 ---------- ---------- Total 182,683 171,668 Less: Current maturity 12,408 7,414 Sinking fund requirement 1,325 1,325 Unamortized debt discount and premium -- net 689 733 ---------- ---------- Total long-term debt 168,261 162,196 ---------- ---------- Total capitalization $391,334 $377,675 ========== ========== See accompanying notes to consolidated financial statements.
Otter Tail Power Company Notes to Consolidated Financial Statements For the Three Years Ended December 31, 1995 1. Summary of accounting policies System of accounts -- The accounting records of the Company conform to the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC), the Public Service Commission of North Dakota, and the Public Utilities Commissions of Minnesota and South Dakota. Principles of consolidation -- The consolidated financial statements include the accounts of the Company and all wholly owned subsidiaries. All significant intercompany transactions have been eliminated. Plant, retirements, and depreciation -- Utility plant is stated at original cost and the cost of additions includes contracted work, direct labor and materials, allocable overheads, and allowance for funds used during construction. The cost of depreciable units of property retired plus removal costs less salvage is charged to the accumulated provision for depreciation. Maintenance, repairs, and replacement of minor items of property are charged to operating expenses. Repairs to property made necessary by storm damage are charged to the reserve therefor. The provisions for utility depreciation for financial reporting purposes are made on the straight-line method based on the estimated service lives of the properties. Such provisions as a percent of the average balance of depreciable property were 2.97% in 1995, 2.98% in 1994, and 2.95% in 1993. Property and equipment of nonutility and subsidiary operations are carried at historical cost, or at the current appraised value if acquired in a business combination, and are depreciated on a straight-line basis over the useful lives (3 to 40 years) of the related assets. Upon sale or retirement of property and equipment, the cost and related accumulated depreciation are eliminated from the respective accounts and the resulting gain or loss is included in the consolidated financial statements. Jointly owned plants -- The consolidated financial statements include the Company's 53.9% and 35% ownership interests in the assets, liabilities and expenses of the Big Stone and Coyote Plants, respectively. Amounts at December 31, 1995 and 1994, included in Plant in Service for Big Stone were $108,577,000 and $107,872,000, respectively, and the accumulated provision for depreciation and amortization was $62,486,000 and $59,757,000, respectively. Amounts at December 31, 1995 and 1994, included in Plant in Service for Coyote were $143,748,000 and $143,445,000, respectively, and the accumulated provision for depreciation and amortization was $54,441,000 and $50,918,000, respectively. The Company's share of direct expenses of the jointly owned plants in service is included in the corresponding operating expenses in the statement of income. Allowance for funds used during construction (AFC) -- AFC, a noncash item, is included in construction work in progress based on a composite rate that assumes that funds used for construction were provided by borrowed funds and equity funds. The AFC so included in construction work in progress will ultimately be included in the rate base used in establishing rates for utility services. The composite rate for AFC was 9.50% for 1995 and 10.25% for both 1994 and 1993. Income taxes -- Comprehensive interperiod income tax allocation is used for substantially all book and tax temporary differences. Deferred income taxes arise for all temporary differences between pretax financial and taxable income, and between the book and tax basis of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect when the temporary differences reverse. The Company amortizes the investment tax credit over the estimated lives of the related property. Operating revenues -- Electric customers' meters are read and bills are rendered on a cycle basis. Prior to 1993 the Company in all of its jurisdictions recorded electric revenues based on billing dates. Effective January 1, 1993, due to a North Dakota Public Service Commission (NDPSC) order, the Company changed its method of revenue recognition in North Dakota from billing dates to energy delivery dates. (See note 3 for further information on the order.) The North Dakota unbilled revenue amount as of January 1, 1993, ($4.4 million) is required by the order to be amortized to electric revenues over 36 months. The change in method of revenue recognition resulted in additional net income of $870,000 in 1993, $751,000 in 1994 and $984,000 in 1995. The impact on earnings per share was $.08 in 1993, $.07 in 1994 and $.09 in 1995. The Company's rate schedules applicable to substantially all customers include a cost of energy adjustment clause under which the rates are adjusted to reflect changes in average cost of fuels and purchased power. Since July 1, 1995, rate schedules applicable to Minnesota customers also include a .5030% surcharge for recovery of conservation-related expenses. (See further discussion under note 3.) Health services' operating revenues on major equipment and installation contracts are recorded using the percentage-of-completion method. Amounts received in advance under customer service contracts are deferred and recognized on a straight-line basis over the contract period. Manufacturing revenues are recorded when products are shipped, when services are rendered, and on a percentage-of-completion basis for large items that are assembled over several months. Other business operations' operating revenues are recorded when services are rendered, products are shipped and, in the case of construction contracts, the percentage-of-completion method is used. Storm damage reserve -- The Company is required under its Indenture of Mortgage to make annual provisions for storm damage of not less than .5% of gross electric operating revenues. Provisions for loss have been used in determining rates approved by the applicable regulatory commissions. Provisions for 1995, 1994, and 1993 were $1,800,000, $995,000, and $1,164,000, respectively, and repairs charged to such reserves were $1,597,000, $1,269,000, and $1,083,000, respectively. Accrued liabilities included $1,060,000 and $857,000 for storm damage at December 31, 1995 and 1994, respectively. Employee incentive plan -- Effective January 1, 1988, the Company established a gain sharing plan for the benefit of all employees. The totals received by all employees for 1995, 1994, and 1993 were $870,000, $1,314,000, and $1,172,000, respectively. Use of Estimates -- In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, environmental loss contingencies, unbilled revenues and actuarially determined benefit costs. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Recent changes in interest rates have resulted in changes to actuarial assumptions used in the benefit cost calculations for postretirement benefits. Also, the depreciable lives of certain plant assets are reviewed and, if appropriate, revised each year, as discussed previously. (See Note 8 for more information on the effects of these changes in estimates.) Reclassifications -- Certain prior year amounts have been reclassified to conform to 1995 presentation. Such reclassification had no impact on net income and shareholders' equity. Cash equivalents -- The Company considers all highly liquid debt instruments purchased with a maturity of 90 days or less to be cash equivalents. Consolidated Statements of Cash Flows -- Excluded from the Consolidated Statements of Cash Flows, are the following noncash transactions: In September of 1995, the Company recorded a $3.5 million passive investment in the form of a delayed equity contribution to a limited liability company. As of December 31, 1995, the Company had made actual cash contributions of $467,000 on its obligation. The remaining balance of $3,033,000, to be paid before August 1, 1996, is included in Other Current Liabilities on the Company's December 31, 1995, Balance Sheet. The Company has recorded an investment of $2 million of which $780,000 remains payable on March 1, 1996, in the form of a delayed equity contribution to a limited partnership that invests in tax-credit qualifying affordable housing. Debt reacquisition premiums -- In accordance with regulatory treatment, the Company defers debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. Investments -- The Company's temporary cash investments consist of money market funds recorded at cost, which approximates market. At December 31, 1994, the Company had noncurrent investments of preferred stock which were recorded at fair value. (See further discussion under note 10.) Inventories -- The electric operation inventories are reported at average cost. The health service, manufacturing and other business operation inventories are stated at the lower of cost (first-in, first-out) or market. Short-term debt -- The composite interest rate on short-term debt outstanding as of December 31, 1994, was 6.5%. Intangible assets -- The majority of the Company's intangible assets consist of Goodwill associated with the acquisition of subsidiaries and are amortized on a straight-line basis over periods of 40 years for the telephone company acquired in August of 1992 and 15 years or less for all other intangibles. The Company periodically evaluates the recovery of intangible assets based on an analysis of undiscounted future cash flows. Total intangibles as of December 31 are as follows: 1995 1994 ------ ------ (in thousands) Goodwill on telephone company $ 7,749 $ 7,749 Other intangible assets 15,797 11,233 ------- ------- Total 23,546 18,982 Less accumulated amortization 4,644 3,502 ------- ------- Intangibles-net $18,902 $15,480 2. Segment information The Company's wholly-owned subsidiary Mid-States Development, Inc. purchased two additional manufacturing companies and three small diagnostic imaging companies in 1995, one additional business in 1994, and six businesses in 1993. Of the companies purchased in 1995, one manufacturing company and all three diagnostic imaging companies were purchased in January, the other manufacturing company was purchased in October. In all acquisitions, the purchase method of accounting was used and the acquisitions would have had no significant pro forma effect on the Company's operating revenues, net income, or earnings per share for 1995, 1994, and 1993. The total acquisition price for all businesses was $20,704,000. The Company has operations in four business areas. Electric operations includes the electric utility only. Health services operations consists of businesses involved in the sale, service, rental, refurbishing and operations of medical imaging equipment and the sale of related supplies and accessories to various medical institutions primarily in midwestern United States. Manufacturing operations include production of agricultural equipment, plastic pipe, and fabricated metal parts. Other business operations consists of businesses diversified in such areas as electrical and telephone construction contracting, radio broadcasting, waste incinerating, and telecommunications. Information for the business segments for 1995, 1994 and 1993 is presented in the table below: 1995 1994 1993 ------ ------ ------ (in thousands) Operating revenue Electric $203,925 $198,812 $192,290 Health services 50,896 45,555 32,068 Manufacturing 38,690 13,083 8,473 Other business operations 35,130 30,073 32,396 -------- -------- -------- Total $328,641 $287,523 $265,227 Pretax operating income Electric $ 47,916 $ 48,126 $ 47,114 Health services 3,581 2,486 2,268 Manufacturing 3,270 2,441 1,049 Other business operations 5,024 3,391 3,555 -------- -------- -------- Total $ 59,791 $ 56,444 $ 53,986 Income taxes 16,584 15,931 14,331 -------- -------- -------- Consolidated operating income $ 43,207 $ 40,513 $ 39,655 Depreciation and amortization Electric $ 19,448 $ 18,970 $ 18,219 Health services 517 455 435 Manufacturing 344 227 227 Other business operations 1,600 1,538 1,631 -------- -------- -------- Total $ 21,909 $ 21,190 $ 20,512 Capital expenditures Electric $ 27,443 $ 25,693 $ 24,526 Health services 4,020 2,544 3,471 Manufacturing 3,879 357 479 Other business operations 1,792 1,817 2,418 -------- -------- -------- Total $ 37,134 $ 30,411 $ 30,894 Identifiable assets Electric $509,588 $505,291 $498,440 Health services 41,623 26,415 23,175 Manufacturing 27,270 7,215 5,815 Other business operations 30,715 40,051 36,475 -------- -------- -------- Total $609,196 $578,972 $563,905 3. Rate matters On July 1, 1995, the Company began charging all Minnesota customers a .5030% surcharge on their electric service statements for recovery of conservation-related costs exceeding the amount already included in base rates. The conservation-related costs being recovered through the surcharge and in base rates include Conservation Improvement Program (CIP) expenditures, carrying charges on costs incurred in excess of costs currently being recovered, lost margins on avoided kilowatt-hour sales, and bonus incentives related to energy savings. The MPUC approved recovery of 1994 lost margins and bonus incentives in 1995. The Company recorded revenues related to 1995 and 1994 lost margins and bonus incentives of $477,000 and $537,000, respectively. As these costs are recovered through the monthly billing process, the amounts billed are offset by the amortization of deferred (CIP) charges. In 1994 the Company filed a petition with the MPUC for approval of an annual recovery mechanism for DSM-related costs, under Minnesota's CIP. An intervenor, on behalf of the large general service group, filed comments against the petition and requested the MPUC to order a general rate case to review the Company's earnings levels. In the interest of rate stability the Company reached an agreement, which was approved by the MPUC, resulting in costs of approximately $2.2 million each year for three years which must be absorbed in current rates starting in 1995. On September 22, 1993, the NDPSC entered an order approving an agreement for incentive regulation for 1993. The Agreement provided a mechanism for sharing equally between ratepayers and shareholders any amounts earned in 1993 over or under a specified return on rate base in North Dakota. As part of the calculation, the NDPSC will allow the Company to recognize postretirement benefits other than pensions under the accrual method required by SFAS 106. The NDPSC's order also requires the Company to change its method of revenue recognition in North Dakota as of January 1, 1993, from billing dates to energy delivery dates. (See "operating revenues" under note 1 for more information on the accounting for unbilled revenue.) As a result of 1993 Incentive Regulation, the Company refunded $413,000, plus accrued interest, to its North Dakota customers in December 1994. Incentive regulation was not in place in 1994 or 1995. 4. Common shares The Company's stock repurchase plan, extended by the Company in 1993, expired on December 31, 1995. The purpose of the plan was to reduce the common equity portion of the Company's capital structure. A total of 787,376 shares were purchased under the program, which began in 1989. No shares were purchased in 1995, 1994 or 1993. 5. Retained earnings restriction The Company's Indenture of Mortgage and Articles of Incorporation, as amended, contain provisions that limit the amount of dividends that may be paid to common shareholders. Under the most restrictive of these provisions, retained earnings at December 31, 1995, were restricted by $9,686,000. 6. Commitments At December 31, 1995, the Company had commitments under contracts in connection with construction programs aggregating approximately $7,500,000. For capacity requirements the Company has agreements extending through April of 2005, at annual costs of approximately $8,000,000 in 1996, $2,800,000 in 1997, $2,300,000 in each year of 1998 through 2004 and $760,000 in 2005. The Company also has several long-term coal contracts in which the Company is responsible for making payment only upon the delivery of the coal. The risk of loss from nonperformance of the contracts is considered nominal because of the availability of other suppliers and the expected continued reliability of the current fuel suppliers. Furthermore, the cost of energy adjustment provision in the rate-making process lessens the risk of loss (in the form of increased costs) from market price changes because it assures recovery of almost all fuel costs. The Company has entered into an agreement to acquire new aluminum coal cars for transporting coal to Big Stone Plant beginning in September of 1996. The Company intends to lease the cars under an operating lease with a term of 15-20 years and annual lease payments approximating $1 million per year. 7. Long-term obligations Preferred shares -- On November 12, 1993, the Company retired 40,000 shares of the $9.50 series. The $6.35 cumulative preferred shares are redeemable in whole or in part at the option of the Company after December 1, 1997, at $103.175. The $9.00 exchangeable cumulative preferred shares are redeemable in whole or in part at the option of the Company after August 9, 1999, for $100.00 per share payable in cash or, at the holder's election, common shares. Subject to certain conditions, such shares are exchangeable at the option of the holder after August 9, 1999, for $100.00 per share in cash or common shares. Long-term debt -- All utility property, with certain minor exceptions, is subject to the lien of the Indenture of Mortgage of the Company securing its First Mortgage Bonds. The Company is required by the Indenture to make annual payments (exclusive of redemption premiums) for sinking fund purposes, except that the requirement with respect to certain series may be satisfied by the delivery of bonds of such series of equal principal amount. The Company issued First Mortgage Bonds of its pollution control and industrial development series to secure payment of a like principal amount of revenue bonds that were issued by local governmental units to finance facilities leased or purchased and that the Company has capitalized. The aggregate amounts of maturities and sinking fund requirements on bonds outstanding and other long-term obligations at December 31, 1995, for each of the next five years are $13,733,000 for 1996, $29,979,000 for 1997, $10,010,000 for 1998, $5,007,000 for 1999, and $4,488,000 for 2000. 8. Pension plan and other postretirement benefits The Company's noncontributory funded pension plan covers substantially all electric utility employees. The plan provides 100% vesting after 5 vesting years of service and for retirement compensation at age 65, with reduced compensation in cases of retirement prior to age 62. The Company reserves the right to discontinue the plan, but no change or discontinuance may affect the pensions theretofore vested. The Company's policy is to fund pension costs accrued. All past service costs have been provided for. The total pension expense was $1,009,000 for 1995, $1,356,000 for 1994, and $1,333,000 for 1993. A portion of the pension expense is capitalized as a part of utility plant construction. The pension plan has a trustee who is responsible for pension payments to retirees. Five investment managers are responsible for managing the plan's assets. In addition, an independent actuary performs the necessary actuarial valuations for the plan. Net periodic pension cost for 1995, 1994, and 1993 includes the following components: 1995 1994 1993 ------ ------ ------ (in thousands) Service cost-benefit earned during the period $ 1,908 $ 2,076 $ 1,774 Interest cost on projected benefit obligation 6,511 6,209 5,867 ------- ------- ------- $ 8,419 $ 8,285 $ 7,641 (Gain)/loss on return on assets (26,509) 3,234 (7,636) Plus/(less): net deferral and amortization 19,099 (10,163) 1,328 ------- ------- ------- Net periodic pension cost $ 1,009 $ 1,356 $ 1,333 ======= ======= ======= The assumptions used for actuarial valuations were: 1995 1994 1993 ------ ------ ------ Discount rate 7.25% 8.00% 7.50% Rate of increase in future compensation level 4.25% 4.50% 4.50% Long-term rate of return on assets 8.50% 8.50% 8.00% The plan assets consist of common stock and bonds of public companies, U.S. Government Securities, cash and cash equivalents. The funded status of the plan and amounts recognized on the balance sheet at December 31, 1995 and 1994, are as follows: 1995 1994 ------ ------ (in thousands) Actuarial present value of benefit obligation: Vested benefits $ 69,340 $ 60,528 Nonvested benefits 8,594 7,645 -------- -------- Accumulated benefit obligation $ 77,934 $ 68,173 ======== ======== Projected benefit obligation $ 95,359 $ 83,653 Plan assets at fair value 110,728 87,313 -------- -------- Funded status $ 15,369 $ 3,660 Unrecognized transition asset (1,486) (1,722) Unrecognized prior service cost 9,200 10,079 Unrecognized net actuarial (gain) or loss (18,057) (7,581) -------- -------- Net pension asset $ 5,026 $ 4,436 ======== ======== In addition to providing pension benefits to all employees, the Company has an unfunded, nonqualified benefit plan for executive officers and certain key management employees. This plan provides defined benefit payments to these employees upon their retirements or to their beneficiaries upon their deaths for a 15-year period. Life insurance carried on the plan participants is payable to the Company upon the employee's death. The net periodic pension cost of this program in 1995, 1994 and 1993 was $412,000, $271,000, and $141,000, respectively. The funded status of the plan and amounts recognized on the balance sheet at December 31, 1995 and 1994, are as follows: 1995 1994 ------ ------ (in thousands) Actuarial present value of benefit obligation: Vested benefits $ 3,067 $ 1,882 Nonvested benefits 583 575 ------- ------- Accumulated benefit obligation $ 3,650 $ 2,457 ======= ======= Projected benefit obligation $ 3,650 $ 2,457 Plan assets at fair value -- -- ------- ------- Funded Status $(3,650) $(2,457) Unrecognized transition obligation 102 123 Unrecognized prior service cost 1,177 1,235 Unrecognized net actuarial (gain) or loss 1,018 68 Additional liability (1,426) (414) ------- ------- Accrued benefit liability $(2,779) $(1,445) ======= ======= The assumptions used for actuarial valuations for 1995 and 1994 were discount rates of 7.5% and 8.0% respectively and a salary scale rate increase of 5%. In addition to providing pension benefits, the Company provides a portion of health insurance and life insurance benefits for retired employees. Substantially all of the Company's electric utility employees may become eligible for health insurance and life insurance benefits if they reach age 55 and have 10 years of service. Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106 - Employers' Accounting for Postretirement Benefits Other Than Pensions (SFAS 106). SFAS 106 requires the Company to accrue the estimated cost of retiree benefit payments during the years the employee provides service. The Company previously expensed the cost of these benefits, which are principally health care, as claims were incurred. The Company has elected to recognize the transitional obligation of approximately $17,619,000 over a period of twenty years. The plan was amended during the fourth quarter of 1995 to reduce the contribution required of an employee's surviving spouse for health insurance. This amendment increased benefit costs by $2,155,000 in 1995 because most of the prior service cost was related to retired employees' spouses for which the Company has no current economic benefit. The Company estimates this amendment will have a service cost of approximately $200,000 per year in future years. The Company's cash flows are not affected by implementation of SFAS 106. The net postretirement benefit cost for 1995, 1994, and 1993 includes the following components: 1995 1994 1993 ------ ------ ------ (in thousands) Service cost - benefit earned during the period $ 411 $ 596 $ 502 Interest cost on accumulated postretirement benefit obligation 1,187 1,412 1,367 Amortization of transition obligation 881 881 881 Amortization of experience (gain)/loss (311) -- -- Plan amendment prior service cost 2,155 -- -- ------ ------ ------ Net postretirement benefit cost $4,323 $2,889 $2,750 ====== ====== ====== The funded status of the plan and the amounts recognized on the balance sheet at December 31, 1995 and 1994, are as follows: 1995 1994 ------ ------ (in thousands) Actuarial present value of benefit obligation: Retirees $ 10,276 $ 10,377 Fully eligible plan participants 5,000 5,289 Other active plan participants 2,607 3,576 -------- -------- Accumulated postretirement benefit obligation $ 17,883 $ 19,242 Plan assets at fair value -- -- -------- -------- Funded status $(17,883) $(19,242) Unrecognized (gain)/loss (4,662) (566) Unrecognized transitional obligation 14,976 15,857 -------- -------- Postretirement benefit liability $ (7,569) $ (3,951) ======== ======== The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation as of December 31, 1995, was 9.5% for 1996, decreasing linearly each successive year until it reaches 5% in 2001, after which it remains constant. The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation as of December 31, 1994, was 10.5% for 1995, decreasing linearly each successive year until it reaches 5% in 2001, after which it remains constant. The assumed discount rates used in determining the accumulated postretirement benefit obligation as of December 31, 1995 and 1994, were 7.25% and 8%, respectively. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement obligation as of December 31, 1995, by approximately 13% and the service and interest cost components of the net postretirement health care cost in 1995 by approximately 15%. The Company has a leveraged employee stock ownership plan (ESOP) for the benefit of all its employees. Contributions made by the Company were $993,000 for 1995, $970,000 for 1994, and $940,000 for 1993. 9. Compensating balances and short-term borrowings The Company maintains formal bank lines of credit for its electric utility operations separate from lines and letters of credit maintained by the subsidiary companies. They make available to the Company bank loans for short-term financing and provide backup financing for commercial paper notes. At December 31, 1995, the Company maintained no compensating balances to support formal bank lines of credit. The Company's bank lines of credit for electric utility operations totaled $30,000,000 of which none was used at December 31, 1995. The subsidiary companies' bank lines and letters of credit, which require no compensating balances, totaled $19,850,000 of which $7,236,000 was used at December 31, 1995. Based on the terms and nature of use of the subsidiaries' lines, outstanding amounts are reflected in long-term debt and current maturities on the Company's consolidated balance sheets. 10. Fair value of financial instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Cash and short-term investments -- The carrying amount approximates fair value because of the short-term maturity of those instruments. Marketable securities -- The fair value of investments are estimated based on quoted market prices. Other investments -- The carrying amount approximates fair value. A portion of other investments are in financial instruments that have variable interest rates that reflect fair value. The remainder of other investments is accounted for by the equity method which, in the case of operating losses, results in a reduction of the carrying amount. Redeemable preferred stock -- The fair value is estimated based on the current rates available to the Company for the issuance of redeemable preferred stock. Long-term debt -- The fair value of the Company's long-term debt is estimated based on the current rates available to the Company for the issuance of debt. 1995 1994 ------------------ ------------------ (in thousands) Carrying Fair Carrying Fair amount value amount value -------- -------- -------- -------- Cash and short-term investments $ 4,075 $ 4,075 $ 2,243 $ 2,243 Marketable securities -- -- 17,132 17,132 Other investments 12,716 12,716 5,801 5,801 Redeemable preferred stock (18,000) (18,650) (18,000) (17,487) Long-term debt (168,261) (183,099) (162,196) (160,694) Effective January 1, 1994, the Company adopted Statement of Financial Accounting Standards No. 115 - Accounting for Certain Investments in Debt and Equity Securities (SFAS 115). SFAS No. 115 establishes standards of financial accounting and reporting for investments in equity securities that have readily determinable values and for all investments in debt securities. The Company's marketable securities are included in investments on the balance sheet and are classified as available for sale. These securities are recorded at fair value with any unrealized gain or loss included as a separate component in the retained earnings on the balance sheet. Realized gains and losses are computed on each specific investment sold. The amounts recognized on the balance sheet as of December 31, 1995 and 1994 and amounts sold for each year are as follows: 1995 1994 ------ ------ (in thousands) Available for sale - securities Cost $-- $18,268 Gross unrealized gain -- 99 Gross unrealized loss -- (1,235) ------- ------- Fair value $-- $17,132 ======= ======= Proceeds from sale $90,774 $39,092 Gross realized gains 1,591 993 Gross realized losses (2,816) (1,066) 11. Income tax expense The total income tax expense differs from the amount computed by applying the federal income tax rate (35% in 1995, 1994 and 1993) to net income before total income tax expense for the following reasons: 1995 1994 1993 ------ ------ ------ (in thousands) Tax computed at federal statutory rate $15,786 $15,525 $14,495 Increases (decreases) in tax from: State income taxes net of federal income tax benefit 2,097 2,088 1,926 Investment tax credit amortization (1,177) (1,347) (1,234) Depreciation differences -- flow-through method reversal 222 617 649 Differences reversing in excess of federal rates (754) (707) (635) Dividend received/paid deduction (872) (889) (824) Permanent and other differences 857 594 (333) ------- ------- ------- Total Income tax expense $16,159 $15,881 $14,044 ======= ======= ======= Overall effective federal and state income tax rate 35.8% 35.8% 33.9% Income tax expense is comprised of the following: Charged (credited) to operations: Current federal income taxes $13,840 $12,892 $ 9,288 Current state income taxes 3,201 2,935 2,344 Deferred federal income taxes 603 1,185 3,275 Deferred state income taxes 117 266 658 Investment tax credit amortization (1,177) (1,347) (1,234) ------- ------- ------- Total $16,584 $15,931 $14,331 Charged (credited) to other income and deductions: Current federal income taxes (269) 115 (192) Current state income taxes (21) 50 (11) Deferred federal and state income taxes (135) (215) (84) ------- ------- ------- Total Income tax expense $16,159 $15,881 $14,044 ======= ======= ======= The Company's deferred tax assets and liabilities were comprised of the following on December 31, 1995 and 1994: 1995 1994 ------ ------ (in thousands) Deferred tax assets Amortization of tax credits $ 13,782 $ 14,544 Vacation accrual 953 844 Unbilled/unearned revenue 3,886 3,864 Operating reserves 5,137 3,572 Nondeductible land - plant abandonment 1,134 1,134 Transfer to regulatory asset (689) (790) Other 1,364 1,716 -------- -------- Total deferred tax assets $ 25,567 $ 24,884 -------- -------- Deferred tax liabilities Differences related to property (114,081) (110,062) Excess tax over book - pensions (1,994) (1,759) Transfer to regulatory asset (2,563) (1,157) Transfer to regulatory liability 649 657 Other (3,222) (3,168) --------- --------- Total deferred tax liabilities $(121,211) $(115,489) --------- --------- Deferred income taxes $ (95,644) $ (90,605) ========= ========= 12. Property, plant and equipment December 31, 1995 1994 ------ ------ (in thousands) Production $ 302,601 $ 300,712 Transmission 132,031 129,627 Distribution 207,248 198,163 General 73,425 69,935 Other nonelectric plant 54,266 36,221 --------- --------- 769,571 734,658 Less accumulated depreciation & amortization 308,174 287,902 --------- --------- 461,397 446,756 Construction work in progress 16,285 10,485 --------- --------- Net plant $ 477,682 $ 457,241 ========= ========= 13. Quarterly information (unaudited) The quarterly data shown below reflects seasonal and timing variations that are common in the utility industry. Three Months Ended --------------------------------------------------------------------- March 31 June 30 September 30 December 31 --------------- --------------- --------------- --------------- 1995 1994 1995 1994 1995 1994 1995 1994 ------ ------ ------ ------ ------ ------ ------ ------ (in thousands except per share data) Operating revenues $83,963 $73,436 $73,807 $68,917 $81,048 $71,142 $89,823 $74,028 Operating income $12,598 $12,347 $8,572 $8,267 $11,022 $8,943 $11,015 $10,956 Net income $8,707 $9,356 $5,337 $5,397 $7,147 $5,905 $7,754 $7,817 Earnings available for common shares $8,118 $8,766 $4,747 $4,808 $6,557 $5,315 $7,165 $7,228 Earnings per common share $.73 $.78 $.42 $.43 $.59 $.48 $.64 $.65 Dividends paid per common share $.44 $.43 $.44 $.43 $.44 $.43 $.44 $.43 Price range: high $35 $34 3/4 $35 $34 $35 1/4 $34 3/4 $37 3/4 $34 3/4 low $31 3/4 $29 1/2 $30 3/4 $29 1/2 $32 1/4 $29 3/4 $34 1/8 $29 3/4 Average number of common shares outstanding 11,180 11,180 11,180 11,180 11,180 11,180 11,180 11,180
Independent Auditors' Report To the Shareholders of Otter Tail Power Company: We have audited the accompanying consolidated balance sheets and statements of capitalization of Otter Tail Power Company and its subsidiaries (the Company) as of December 31, 1995 and 1994, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1995. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP January 29, 1996 Minneapolis, Minnesota EX-21 4 Exhibit 21-A OTTER TAIL POWER COMPANY Subsidiaries of the Registrant March 1, 1996 Company State of Organization Minnesota Dakota Generating Company Minnesota Otter Tail Realty Company Minnesota Otter Tail Management Corporation* Minnesota ORD Corporation* Minnesota Quadrant Co. Minnesota North Central Utilities, Inc. Minnesota Midwest Information Systems, Inc. Minnesota Midwest Telephone Co. Minnesota Osakis Telephone Company Minnesota Data Video Systems, Inc. Minnesota MIS Investments, Inc. Minnesota Mid-States Development, Inc. Minnesota Glendale Machining, Inc. Minnesota Precision Machine of North Dakota, Inc. North Dakota Dakota Machine, Inc. North Dakota Aerial Contractors, Inc. North Dakota Moorhead Electric, Inc. Minnesota KFGO, Inc. North Dakota Western Minnesota Broadcasting Company Minnesota Imaging Plus, Inc. North Dakota Mobile Imaging, Inc. North Dakota Diagnostic Medical Systems, Inc. North Dakota DMS Leasing Corporation North Dakota Medical Operators and Management Corp. North Dakota BTD Manufacturing, Inc. Minnesota Northern Pipe Products, Inc. North Dakota Radiographic Supply, Inc. Montana Dakota Engineering, Inc. North Dakota Fargo Baseball, LLC Minnesota *Inactive EX-24 5 POWER OF ATTORNEY __________ I, JEFFREY J. LEGGE, do hereby constitute and appoint JOHN C. MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Controller and Principal Accounting Officer of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: _______1/8_____________, 1996. _______Jeffrey J. Legge____________ Jeffrey J. Legge In Presence of: _______Kathy Kowalski____________ _______Todd Wahlund______________ POWER OF ATTORNEY __________ I, JOHN C. MAC FARLANE, do hereby constitute and appoint A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as President and Chief Executive Officer, Principal Executive Officer and Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: ______12/22 _________, 1995. _______John C. MacFarlane____________ John C. MacFarlane In Presence of: _______Penny Mosher________________ _______Dee Fletcher_______________ POWER OF ATTORNEY __________ I, ROBERT N. SPOLUM, do hereby constitute and appoint JOHN C. MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: _____12/26__________, 1995 ______Robert N.Spolum________________ Robert N. Spolum In Presence of: _______Linda Brenzel_______________ _______Michele Pingel______________ POWER OF ATTORNEY __________ I, NATHAN I. PARTAIN, do hereby constitute and appoint JOHN C. MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: ______1/9___________, 1996. ______Nathan I. Partain______________ Nathan I. Partain In Presence of: ______Tom Lewis____________________ ______James C. Hermann_____________ POWER OF ATTORNEY __________ I, DAYLE DIETZ, do hereby constitute and appoint JOHN C. MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: ______1/4___________, 1996. ______Dayle Dietz____________________ Dayle Dietz In Presence of: ________Diane S. Pederson__________ ________Owen E. Jensen_____________ POWER OF ATTORNEY __________ I, ARVID R. LIEBE, do hereby constitute and appoint JOHN C. MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and ExchangeCommission pursuant to the Securities Exchange Act of 1934, as amended. Date: ________12/26_______, 1995. ______Arvid R. Liebe_________________ Arvid R. Liebe In Presence of: _________Daryl Liebe_______________ _________Susan M. Stengel__________ POWER OF ATTORNEY __________ I, THOMAS M. BROWN, do hereby constitute and appoint JOHN C. MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: _______12/28________, 1995. _____Thomas M. Brown_________________ Thomas M. Brown In Presence of: _____Donna M. Huee_________________ _____Linda J. Barnes_______________ POWER OF ATTORNEY __________ I, C. E. BRUNKO, do hereby constitute and appoint JOHN C. MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, and BEVERLY A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Assistant Treasurer and Assistant Secretary of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: _______1/3__________, 1996. ______C. E. Brunko___________________ C. E. Brunko In Presence of: _______Susan K. Vukonich___________ _______Loren K. Hanson_____________ POWER OF ATTORNEY __________ I, MAYNARD D. HELGAAS, do hereby constitute and appoint JOHN C. MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: ________12/28_______, 1995. ______Maynard D. Helgaas_____________ Maynard D. Helgaas In Presence of: _______Ronald Herraas______________ _______Denice S.Nichel_____________ POWER OF ATTORNEY __________ I, KENNETH L. NELSON, do hereby constitute and appoint JOHN C. MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: ___1/29_____________, 1996 _____Kenneth L. Nelson_____ Kenneth L. Nelson In Presence of: _____D. R. Emmen___________________ _____Dayle Dietz___________________ POWER OF ATTORNEY __________ I, DENNIS R. EMMEN, do hereby constitute and appoint JOHN C. MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Director of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: ______1/2___________, 1996 ______Dennis R. Emmen________________ Dennis R.Emmen In Presence of: _______Becky Luhning_______________ _______Penny Mosher________________ POWER OF ATTORNEY __________ I, A. E. ANDERSON, do hereby constitute and appoint JOHN C. MAC FARLANE, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Vice President, Finance of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: ______1/8___________, 1996. _____A. E. Anderson__________________ A. E. Anderson In Presence of: ______Penny Mosher_________________ ______Lori D. Dawkins_____________ POWER OF ATTORNEY __________ I, BEVERLY A. NORLIN, do hereby constitute and appoint JOHN C. MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, and C. E. BRUNKO, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Assistant Secretary of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: ______1/4___________, 1996. ______Beverly A. Norlin______________ Beverly A. Norlin In Presence of: ______Becky Luhning________________ ______Penny Mosher_________________ POWER OF ATTORNEY __________ I, JAY D. MYSTER, do hereby constitute and appoint JOHN C. MAC FARLANE, A. E. ANDERSON, BEVERLY A. NORLIN, and C. E. BRUNKO, or any one of them, my Attorney-in-Fact for the purpose of signing, in my name and on my behalf as Vice President, Governmental & Legal and Corporate Secretary of Otter Tail Power Company, the Annual Report of Otter Tail Power Company on Form 10-K for its fiscal year ended December 31, 1995, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. Date: _______1/2__________, 1996. ______Jay D. Myster__________________ Jay D. Myster In Presence of: _______Becky Luhning_______________ _______Penny Mosher________________ EX-27 6
UT This schedule contains summary financial information extracted from the Consolidated Balance Sheet as of December 31, 1995, and the Consolidated Statement of Income for the twelve months ended December 31, 1995, and is qualified in its entirety by reference to such financial statements. 1,000 12-MOS DEC-31-1995 DEC-31-1995 PER-BOOK 439,850 77,182 78,774 13,390 0 609,196 55,901 30,335 98,006 184,242 18,000 20,831 168,261 0 0 0 13,733 0 0 0 204,129 609,196 328,641 16,584 268,850 285,434 43,207 813 44,020 15,075 28,945 2,358 26,587 19,677 14,558 58,077 2.38 2.38 -----END PRIVACY-ENHANCED MESSAGE-----