================================================================================ Securities and Exchange Commission Washington, D.C. 20549 FORM 10-K (Mark One) /X/ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Fiscal Year Ended December 31, 1995 / / Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ________________ to _______________ Commission File No. 1-3548 Minnesota Power & Light Company (Exact name of registrant as specified in its charter) Minnesota 41-0418150 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 30 West Superior Street Duluth, Minnesota 55802 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (218) 722-2641 Securities registered pursuant to Section 12(b) of the Act: Name of Each Stock Title of Each Class Exchange on Which Registered ------------------- ---------------------------- Common Stock, without par value New York Stock Exchange 5% Cumulative Preferred Stock, par value $100 per share American Stock Exchange Serial Preferred Stock, $7.36 Series, cumulative, without par value American Stock Exchange 8.05% Cumulative Quarterly Income Preferred Securities of MP&L Capital I, a subsidiary of Minnesota Power & Light Company New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Preferred Stock, without par value Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /X/ No / / Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. /X/ The aggregate market value of voting stock held by nonaffiliates on March 1, 1996, was $909,552,265. As of March 1, 1996, there were 31,526,956 shares of Minnesota Power & Light Company Common Stock, without par value, outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Minnesota Power 1995 Annual Report are incorporated by reference in Part II, Items 7 and 8, and portions of the Proxy Statement for the 1996 Annual Meeting of Shareholders are incorporated by reference in Part III. ================================================================================
INDEX Page PART I Item 1. Business 1 Electric Operations 2 Electric Sales 2 Purchased Power 5 Capacity Sales 6 Fuel 6 Regulatory Issues 7 Capital Expenditure Program 10 Competition 10 Franchises 11 Environmental Matters 12 Water Operations 15 Regulatory Issues 15 Capital Expenditure Program 18 Competition 18 Franchises 19 Environmental Matters 19 Automobile Auctions 20 Capital Expenditure Program 21 Competition 21 Environmental Matters 21 Investments 22 Environmental Matters 22 Executive Officers of the Registrant 23 Item 2. Properties 25 Item 3. Legal Proceedings 27 Item 4. Submission of Matters to a Vote of Security Holders 27 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters 28 Item 6. Selected Financial Data 29 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 29 Item 8. Financial Statements and Supplementary Data 29 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 30 PART III Item 10. Directors and Executive Officers of the Registrant 31 Item 11. Executive Compensation 31 Item 12. Security Ownership of Certain Beneficial Owners and Management 31 Item 13. Certain Relationships and Related Transactions 32 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 32 SIGNATURES 39
Definitions The following abbreviations or acronyms are used in the text. Abbreviations or Acronyms Term - ------------------------ --------------------------------------------- ADESA ADESA Corporation BNI Coal BNI Coal, Ltd. Boise Boise Cascade Corp. Boswell Boswell Energy Center Btu British thermal units Capital Re Capital Re Corporation CIP Conservation Improvement Program CPI Consolidated Papers, Inc. Company Minnesota Power & Light Company and its Subsidiaries Duluth City of Duluth, Minnesota Energy Policy Act National Energy Policy Act of 1992 EPA Environmental Protection Agency FERC Federal Energy Regulatory Commission FDEP Florida Department of Environmental Protection FPSC Florida Public Service Commission Heater Heater Utilities, Inc. Hibbard M.L. Hibbard Station Hibbing Taconite Hibbing Taconite Co. Inland Inland Steel Mining Co. Laskin Laskin Energy Center Lehigh Lehigh Acquisition Corporation Manitoba Hydro Manitoba Hydro Electric Board MAPP Mid-Continent Area Power Pool MBtu Million British thermal units Minnesota Power Minnesota Power & Light Company and its Subsidiaries Minnkota Minnkota Power Cooperative, Inc. MPCA Minnesota Pollution Control Agency MPUC Minnesota Public Utilities Commission MW Megawatt(s) MWh Megawatt-hour National National Steel Pellet Co. NCUC North Carolina Utilities Commission Note_ Note_ to the consolidated financial statements in the Minnesota Power 1995 Annual Report NPDES National Pollutant Discharge Elimination System PSCW Public Service Commission of Wisconsin Rainy River Rainy River Energy Corporation Reach All Reach All Partnership SCPSC South Carolina Public Service Commission Square Butte Square Butte Electric Cooperative SSU Southern States Utilities, Inc. SWL&P Superior Water, Light and Power Company Synertec Synertec, Incorporated Topeka Topeka Group Incorporated UtilEquip UtilEquip, Incorporated WPPI Wisconsin Public Power, Inc. SYSTEM
PART I Item 1. Business. Minnesota Power is an operating public utility incorporated under the laws of the State of Minnesota in 1906. Its principal executive office is at 30 West Superior Street, Duluth, Minnesota, 55802; and its telephone number is (218) 722-2641. Minnesota Power has operations in four business segments: (1) electric operations, which include electric and gas services, and coal mining; (2) water operations, which include water and wastewater services; (3) automobile auctions, which also include a finance company and an auto transport company; and (4) investments, which include real estate operations, a 21 percent equity investment in a financial guaranty reinsurance company, and a securities portfolio. As of December 31, 1995, the Company and its subsidiaries had approximately 5,600 employees. Year Ended December 31, Summary of Earnings Per Share 1995 1994 1993 - -------------------------------------------------------------------------------- Consolidated Earnings Per Share Continuing Operations $2.06 $ 1.99 $ 2.27 Discontinued Operations * .10 .07 (.07) ----- ------ ------ Total $2.16 $ 2.06 $ 2.20 ===== ====== ====== Percentage of Earnings by Business Segment Continuing Operations Electric Operations 61% 63% 63% Water Operations (2) 23 4 Automobile Auctions 0 - - Investments 36 11 36 Discontinued Operations * 5 3 (3) --- --- --- 100% 100% 100% === === === * On June 30, 1995, the Company sold the interest in its paper and pulp business to CPI for $118 million in cash, plus CPI's assumption of certain debt and lease obligations. The Company is still committed to a maximum guarantee of $95 million to ensure a portion of a $33.4 million annual lease obligation for paper mill equipment under an operating lease extending to 2012. CPI has agreed to indemnify the Company for any payments the Company may make as a result of the Company's obligation relating to this operating lease. Since 1983 Minnesota Power has been diversifying to reduce its reliance on electricity sales to Minnesota's taconite industry and to gain additional earnings growth potential. Acquisitions have been a primary means of diversification. The Company's most recent acquisition occurred in 1995 when the Company acquired an 80 percent ownership in ADESA, the third largest automobile auction business in the United States. In January 1996 the Company increased its ownership in ADESA to 83 percent. For a detailed discussion of results of operations and trends, see Management's Discussion and Analysis of Financial Condition and Results of Operations in the Minnesota Power 1995 Annual Report. For business segment information, see Note 1. The information contained or incorporated by reference in this annual report on Form 10-K reflects a categorization of the Company's business which is different from the categorization used in the annual report on Form 10-K for 1994. Financial data from prior years has been reclassified in this annual report on Form 10-K to present comparable data in all periods. -1-
Electric Operations Electric operations generate, transmit, distribute and sell electricity. In addition to Minnesota Power, five wholly owned subsidiaries are also included in electric operations - SWL&P, BNI Coal, Rainy River, Synertec and Upper Minnesota Properties, Inc. - Minnesota Power provides electricity in a 26,000 square mile electric service territory located in northern Minnesota. As of December 31, 1995, Minnesota Power was supplying retail electric service to 122,000 customers in 153 cities, towns and communities, and outlying rural areas. The largest city served is Duluth with a population of 85,000 based on the 1990 census. Wholesale electric service for resale is supplied to 13 municipal distribution systems, one private utility and SWL&P. Wholesale non-firm electric service is provided to two customers. Transmission service (wheeling) is provided to four customers. - Superior Water, Light and Power Company sells electricity and natural gas, and provides water service in northwestern Wisconsin. As of December 31, 1995, SWL&P served 14,000 electric customers, 11,000 natural gas customers and 10,000 water customers. - BNI Coal owns and operates a lignite mine in North Dakota. Two electric generating cooperatives, Minnkota and Square Butte, presently consume virtually all of BNI Coal's production of lignite coal under coal supply agreements extending to 2027. Under an agreement with Square Butte, Minnesota Power purchases 71 percent of the output from the Square Butte unit which is capable of generating up to 470 MW. Minnkota has an option to extend its coal supply agreement to 2042. (See - Fuel and Note 12.) - Rainy River and Synertec provide planning, construction management and operating services to new and expanding businesses, and have the ability to participate as an investor when appropriate. - Upper Minnesota Properties, Inc. has invested in affordable housing projects located in Minnesota Power's electric service territory. Electric Sales The two major industries in Minnesota Power's service territory are taconite production, and paper and wood products manufacturing. These two industries contributed about half of the Company's electric operating revenue from 1993 through 1995. Over the last five years, 79 percent of the domestic ore consumed by iron and steel plants in the United States has originated from plants within the Company's Minnesota electric service territory. Taconite, an iron-bearing rock of relatively low iron content which is abundantly available in Minnesota, is an important domestic source of raw material for the steel industry. Taconite processing plants use large quantities of electric power to grind the ore-bearing rock and agglomerate and pelletize the iron particles into taconite pellets. Annual taconite production in Minnesota was 47 million tons in 1995, 43 million tons in 1994, 41 million tons in 1993, 40 million tons in 1992, and 41 million tons in 1991. The Company estimates that 1996 Minnesota taconite production will be about 48 million tons. While taconite production is expected to continue near record setting levels, the long-term future of this cyclical industry is less certain. Even with the Company's commitment to help the taconite customers remain competitive, it is possible production will decline gradually some time after the year 2005. -2-
The Company continues to explore opportunities to expand services and assistance provided to its customers, as well as increase sales beyond the Company's traditional service territory. Year Ended December 31, Summary of Electric Revenue and Income 1995 1994 1993 - -------------------------------------------------------------------------------- Total Electric Revenue and Income (000s) $498,352 $453,287 $457,719 Percentage of Total Electric Revenue and Income Retail Industrial Taconite and Iron Mining (1) 35% 34% 34% Paper and Other Wood Products 12 13 14 Other Industrial 7 8 8 --- --- --- Total Industrial 54 55 56 Residential 12 12 11 Commercial 12 12 11 Other Retail 3 3 4 Resale (2) 9 8 7 Other Revenue and Income 10 10 11 --- --- --- 100% 100% 100% === === === (1) The Company's largest customers, Minntac and Hibbing Taconite, represented 12 percent and 9 percent, respectively, of total electric revenue and income in 1995, and 13 percent and 10 percent, respectively, in 1994 and in 1993. (2) The Company sold 183 MW of firm energy to resale customers in 1995. (See Regulatory Issues - Federal Energy Regulatory Commission.) Large Power Customer Contracts The Company has Large Power Customer contracts with five taconite producers, five paper manufacturers and a pipeline company (Large Power Customers). Large Power Customer contracts require the Company to have a certain amount of capacity available at all times (Firm Power). Each contract requires 10 MW or more of power and payment of a minimum monthly demand charge that covers most of the fixed costs associated with having capacity available to serve the customer, including a return on common equity. Such contracts minimize the impact on earnings that otherwise would result from significant reductions in kilowatt-hour sales to such customers. These contracts, which are subject to MPUC approval, have a minimum contract term of ten years initially, with a four-year cancellation notice required for termination of the contact at or beyond the end of the tenth year. The rates and corresponding revenue associated with capacity and energy provided under these contracts are subject to change through the same regulatory process governing all retail electric rates. (See Regulatory Issues-Electric Rates.) As of March 15, 1996, the minimum annual revenue the Company would collect under contracts with these Large Power Customers, assuming no electric energy use by these customers, is estimated to be $103.8, $92.0, $80.1, $62.9 and $49.2 million during the years 1996, 1997, 1998, 1999 and 2000, respectively. The Company believes actual revenue received from these Large Power Customers will be substantially in excess of the minimum contract amounts. -3-
<TABLE> Contract Status for Minnesota Power Large Power Customers as of March 15, 1996 <CAPTION> Firm Contracted Earliest Plant and Location Operating Agent Ownership MW <F1> Termination Date - ------------------ --------------- --------- ---------- ---------------- <S> <C> <C> <C> <C> Eveleth Mines Oglebay Norton Co. 41.7% Rouge Steel Co. 67.0 <F2> October 31, 1999 Eveleth, MN 14.4% Oglebay Norton Co. 33.3% AK Steel 10.6% Steel Co. of Canada Hibbing Taconite Co. Cliffs Mining 50% Bethlehem Hibbing Corp. 151.5 <F3> December 31, 2001 Hibbing, MN Company 10% Cliffs Mining Company 6.67% Ontario Hibbing Company 33.33% Hibbing Development Co. Inland Steel Mining Co. Inland Steel Mining Inland Steel Co. 47.3 <F4> October 31, 1997 Virginia, MN Co. Minntac (USX) U.S. Steel Co. USX Corp. 198.0 <F5> May 23, 1999 Mt. Iron, MN National Steel Pellet Co. National Steel Corp. National Steel Corp. 85.0 <F6> October 31, 2004 Keewatin, MN Blandin Paper Co. Blandin Paper Co. Fletcher Challenge 57.0 <F7> December 31, 2003 Grand Rapids, MN Canada Ltd. Boise Cascade Corp. Boise Cascade Corp. Boise Cascade Corp. 32.0 <F8> December 31, 1998 International Falls, MN Lake Superior Paper Lake Superior Paper Consolidated Papers, Inc. 49.5 <F9> December 31, 2005 Industries Industries Duluth, MN Potlatch Corp. Potlatch Corp. Potlatch Corp. 17.5 <F10> April 30, 1997 Cloquet, MN Potlatch Corp. Potlatch Corp. Potlatch Corp. 10.3 <F11> November 30, 1999 Brainerd, MN Lakehead Pipe Line Lakehead Pipe Line Lakehead Pipe Line 16.5 <F12> April 20, 2001 Deer River, MN Company Inc. Partners, L.P. Floodwood, MN - ------------------------------ The following terms are used in the contract descriptions footnoted below. Firm demand is a take-or-pay obligation which is the sum of contract demand plus incremental demand. Incremental production service is billed on an energy only basis for energy used above a customer's specific demand threshold. This service does not include a take-or-pay obligation. Interruptible service is electrical service for a customer that may be interrupted by the Company under certain conditions. In return for this service, customers receive a reduced demand charge, but are obligated to the Company for future service requirements. Replacement firm power service is electric service that is provided when a customer's generating units are unavailable due to planned or unscheduled outages. <FN> <F1> Firm contracted MW represents take-or-pay obligation for March 1996. <F2> Eveleth Mines has firm demand through October 1999. Contract and incremental demand through October 1996 total 67 MW, from November 1996 through October 1998 total 51 MW, and from November 1998 through October 1999 total 37.8 MW. This contract also provides for 10 MW of interruptible service and varying amounts of incremental production service for loads above 56 MW. <F3> Hibbing Taconite has contract demand of 112.25 MW through December 2001 and incremental demand of approximately 40 MW through December 1997. This contract also provides for 81 MW of interruptible service and incremental production service thresholds at 151.5 MW in winter and 150.5 MW in summer. <F4> Inland has contract demand of 34 MW and incremental demand of between 10 and 11 MW through October 1997. This contract also provides for 18 MW of interruptible service. <F5> Minntac (USX) has contract demand of 150.4 MW and incremental demand of 47.6 MW through April 1996 and contract demand of 95 MW from May 1996 through May 1999. This contract also provides for 21 MW of interruptible service and incremental production service for loads above 203 MW. <F6> National has contract demand of 63 MW and incremental demand of 22 MW through October 2004. This contract also provides for 39 MW of interruptible service and incremental production service for loads over 85 MW. <F7> Blandin Paper has contract demand of 42.3 MW and incremental demand of 14.7 MW through December 2003. The contract also provides for incremental production service and replacement firm power service. <F8> Boise has contract demand of 32 MW through December 1998. <F9> Lake Superior Paper Industries has contract demand of 38 MW and incremental demand of 10 MW through December 2005. This contract also provides for 31 MW of interruptible service and incremental production service for loads above 52 MW. <F10>Potlatch - Cloquet has a contract demand of 14.7 MW through April 1997. <F11>Potlatch - Brainerd has contract demand of 10 MW through November 1999. <F12>Lakehead Pipe Line has contract and incremental demand of 16.5 MW through April 2001. This contract also provides for incremental production service for loads above 16.5 MW. </FN> </TABLE> Purchased Power Minnesota Power has contracts to purchase capacity from various entities. <TABLE> Contract Status of Minnesota Power Purchased Power Contracts <CAPTION> Entity Contract MW Contract Period - ------ ----------- --------------- Participation Power Purchases <F1> - ----------------------------- <S> <C> <C> Square Butte <F2> 333 May 6, 1977 through December 31, 2007 City of Aitkin 2 May 1, 1993 through April 30, 1998 City of Two Harbors 2 May 1, 1993 through April 30, 1998 LTV Steel 210 May 1, 1995 though April 30, 2000 Basin Electric Power Cooperative 50 July 1, 1995 through April 30, 1996 Silver Bay Power 78 November 1, 1995 through October 31, 2000 Firm Power Purchases <F3> City of Hibbing 5 May 1, 1996 through October 31, 1996 City of Virginia 5 May 1, 1996 through October 31, 1996 Ontario Hydro 100 July 1, 1995 through April 30, 1996 - --------------------------- <FN> <F1> Participation power purchase contracts require the Company to pay the demand charges for MW under contract and an energy charge for each MWh purchased. The selling entity is obligated to provide energy as scheduled by the Company from the generating unit specified in the contract as energy is available from that unit. <F2> Under an agreement extending through 2007 with Square Butte, Minnesota Power purchases 71 percent of the output of a mine-mouth generating unit located near Center, North Dakota. The Square Butte unit is one of two lignite-fired units at Minnkota Power Cooperative's Milton R. Young Generating Station. Reductions to about 49 percent of the output are provided for in the contract and, at the option of Square Butte, could begin after a five-year advance notice to the Company. The cost of the power and energy purchased is a proportionate share of Square Butte's fixed obligations and operating costs which are not incurred unless production takes place. The Company is responsible for paying all costs and expenses of Square Butte (including leasing, operating and any debt service costs) if not paid by Square Butte when due. These obligations and responsibilities of the Company are absolute and unconditional, whether or not any power is actually delivered to the Company. (See Note 12.) <F3> Firm power purchase contracts require the Company to pay demand charges for MW under contract and an energy charge for each MWh purchased. The selling entity is obligated to provide energy as scheduled by the Company. </FN> </TABLE> -5-
Capacity Sales Minnesota Power has contracts to sell capacity to nonaffiliated utility companies. <TABLE> Contract Status of Minnesota Power Capacity Sales Contracts <CAPTION> Utility Contract MW Contract Period - ------- ----------- --------------- Participation Power Sales <F1> - ------------------------- <S> <C> <C> Interstate Power Company 55 May 1 through October 31 of each year from 1994 through 2000 20 November 1, 1997 through April 30, 1998 35 November 1, 1998 through April 30, 1999 50 November 1, 1999 through April 30, 2000 Firm Power Sales <F2> Wisconsin Power & Light Company 30 November 1, 1993 through December 31, 1997 75 January 1, 1998 through December 31, 2007 Northern States Power Company 150 May 1 through October 31 of each year from 1994 through 1996 Cooperative Power Association 10 April 1, 1997 through September 30, 1997 Minnkota Power Cooperative 10 May 1 through October 31 of each year for 1995 and 1996 United Power Association 25 November 1, 1995 through April 30, 1996 ENRON Corp. 30 May 1 through October 31 of each year for 1996 and 1997 - ----------------------------- <FN> <F1> Participation power sales contracts require the purchasing utility to pay the demand charges for MW under contract and an energy charge for each MWh purchased. The Company is obligated to provide energy as scheduled by the purchasing utility from the generating unit specified in the contract as energy is available from that unit. <F2> Firm power sales contracts require the purchasing utility to pay the demand charges for MW under contract and an energy charge for each MWh purchased. The Company is obligated to provide energy as scheduled by the purchasing utility. </FN> </TABLE> Fuel The Company has experienced no difficulty in obtaining an adequate fuel supply. The Company purchases low-sulfur, sub-bituminous coal from the Powder River Basin coal field located in Montana and Wyoming to meet substantially all of its coal supply requirements. Coal consumption for electric generation at the Company's Minnesota coal-fired generating stations in 1995 was about 3.6 million tons. As of December 31, 1995, the Company had a coal inventory of about 431,305 tons. During 1995, the Company obtained its coal through both long- and short-term agreements. A long-term agreement (January 1993 through May 1997) with Big Sky Coal Company enables the Company to purchase up to 2.5 million tons of coal on an annualized basis from the Big Sky Mine. Additionally, in August 1994 the Company entered into a separate agreement (November 1994 through May 1997) with Big Sky Coal Company to purchase an additional 600,000 tons of coal on an annualized basis from the Big Sky Mine. The Company also obtained coal under one-year agreements from Kennecott Energy Company's Spring Creek Mine and Western Energy Company's Rosebud Mine. The Company will obtain coal in 1996 under a new long-term agreement with Kennecott Energy Company, a one-year agreement with Decker Coal Company, and will continue to obtain coal under its long-term agreements with Big Sky Coal Company. This mix of coal supply options allows the Company to reduce market risk and to take advantage of favorable spot market prices. The Company is exploring future coal supply options and believes that adequate supplies of low-sulfur, sub-bituminous coal will continue to be available. Burlington Northern Santa Fe Railroad, formerly Burlington Northern Railroad, transports the coal by unit train from Montana or Wyoming to the Company's generating stations. The -6-
Company and Burlington Northern Santa Fe Railroad have two long-term coal freight-rate contracts that provide for coal deliveries through 2002 to Laskin and through 2003 to Boswell. The Company also has a contract with the Duluth Missabe & Iron Range Railway which is the final destination short-hauler to Laskin. This contract provides for deliveries through 2002. The delivered price of coal is subject to periodic adjustments in freight rates. Year Ended December 31, Summary of Coal Delivered to Minnesota Power 1995 1994 1993 - ------------------------------------------------------------------------------- Average Price Per Ton $19.17 $19.27 $19.31 Average Price Per MBtu $1.09 $1.08 $1.07 The generating unit operated by Square Butte, which is capable of generating up to 470 MW, burns North Dakota lignite that is being supplied by BNI Coal, a wholly owned subsidiary of the Company, pursuant to the terms of a contract expiring in 2027. Square Butte's cost of lignite burned in 1995 was approximately 66 cents per MBtu. The lignite acreage that has been dedicated to Square Butte by BNI Coal is located on lands essentially all of which are under private control and presently leased by BNI Coal. This lignite supply is sufficient to provide the fuel for the anticipated useful life of the generating unit. Under the various agreements with Square Butte, the Company is unconditionally obligated to pay all costs not paid by Square Butte when due. These costs include the price of lignite purchased under a cost-plus contract from BNI Coal. (See Item 2. Properties and Note 12.) BNI Coal has experienced no difficulty in supplying all of Square Butte's lignite requirements. Regulatory Issues The Company and its subsidiaries are exempt from regulation under the Public Utility Holding Company Act of 1935, except as to Section 9(a)(2) which relates to acquisition of securities of public utility operations. The Company and its subsidiaries are subject to the jurisdiction of various regulatory authorities. The MPUC has regulatory authority over Minnesota Power's service area, retail rates, retail services, issuance of securities and other matters. The FERC has jurisdiction over the licensing of hydroelectric projects, the establishment of rates and charges for the sale of electricity for resale and for transmission of electricity in interstate commerce, and certain accounting and record keeping practices. The PSCW has regulatory authority over the retail sales of electricity, water and gas by SWL&P. The MPUC, FERC and PSCW had regulatory authority over 56 percent, 7 percent, and 6 percent, respectively, of the Company's 1995 total operating revenue and income. Electric Rates The Company has historically designed its electric service rates based on cost of service studies under which allocations are made to the various classes of customers. Nearly all retail sales include billing adjustment clauses which adjust electric service rates for changes in the cost of fuel and purchased energy, and recovery of current and deferred CIP expenditures. The Company's current policy for all contracts with Large Power Customers is to require a minimum initial contract term of ten years with the term perpetuated thereafter (continuous term) subject to a minimum cancellation notice of four years. The Company's Firm Power rate schedules are designed to recover the fixed costs of providing Firm Power to Large Power Customers, including a return on common equity, regardless of the amount of power or energy actually used. A Large Power Customer's monthly demand charge obligation in any particular -7-
month is determined based upon the greater of its actual demand for electricity or the firm demand amount. Contract and rate schedule provisions provide for adjustment if the customer's firm demand amount is set significantly below the customer's actual electric requirements. The rates and corresponding revenue associated with capacity and energy provided under these contracts are subject to change through the regulatory process governing all retail electric rates. Contracts with ten of the eleven Large Power Customers provide for deferral without interest or diminishment of one-half of demand charge obligations incurred during the first three months of a strike or illegal walkout at a customer's facilities, with repayment required over the 12-month period following resolution of the work stoppage. The Company also has contracts with large industrial and commercial customers who require more than 2 MW but less than 10 MW of capacity (Large Light and Power Customers). The terms of these contracts vary depending upon the customers' demand for power and the cost of extending the Company's facilities to provide electric service. Generally, the contracts for less than 3 MW have one-year terms and the contracts ranging from 3 to 10 MW have initial five-year terms. The Company's rate schedule for Large Light and Power Customers is designed to minimize fluctuations in revenue and to recover a significant portion of the fixed costs of providing service to such customers. The Company requires that all large industrial and commercial customers under contract specify the date when power is first required, and thereafter the customer is billed for at least the minimum power for which it contracted. These conditions are part of all contracts covering power to be supplied to new large industrial and commercial customers and to current contract customers as their contracts expire or are amended. All contracts provide that new rates which have been approved by appropriate regulatory authorities will be substituted immediately for obsolete rates, without regard to any unexpired term of the existing contract. All rate schedules are subject to approval by appropriate regulatory authorities. Federal Energy Regulatory Commission The FERC has jurisdiction over the Company's wholesale electric service resale customers and transmission service (wheeling) customers. In a filing with the FERC on December 22, 1995, the Company requested an overall rate decrease of $138,000 or 0.4 percent with an effective date of January 1, 1996. All of the customers affected by the rate change have submitted written consents to the rate change and effective date. Minor modifications to the rate request were made in an amendment filed on January 16, 1996. The Company expects final rates to be effective by March 31, 1996. The Company has contracts through at least 2007 with twelve of the thirteen Minnesota municipalities receiving full requirements resale service. The December 1995 FERC filing includes a proposed contract amendment for the remaining full requirements municipality to extend its current contract with the Company from 1999 to 2009. The thirteen contracts for the full requirements customers limit rate increases (including fuel costs) to about 2 percent per year on a cumulative basis. In 1995 the 13 municipal customers purchased 88 MW of Firm Power from the Company. Two municipalities whose requirements are only partially supplied by the Company have contracts with the Company through 1999. These municipal customers signed amendments under which the Company will provide exclusive brokering service for the municipalities' purchases of economy energy and will supply emergency, scheduled outage and firm energy as required through 1999. In 1995 these two municipalities purchased 168,987 MWh. A contract between Minnesota Power and SWL&P provides for SWL&P to purchase its power from the Company through at least 1999 and incorporates the same cap on future rate increases as discussed above. The December 1995 FERC filing includes a proposed contract -8-
amendment to extend SWL&P's contract with the Company to at least 2010, with a 2 percent per year cap on rate increases. SWL&P purchased 87 MW of Firm Power from the Company in 1995. The Company also has a contract through December 2004 to supply electricity to Dahlberg Light and Power Company (Dahlberg), a private utility. Dahlberg purchased 8 MW of Firm Power from the Company in 1995. The Company's hydroelectric facilities which are located in Minnesota are licensed by the FERC. In 1995 the FERC issued to the Company a 30-year license for the St. Louis River hydroelectric project (87.6 MW generating capability). On May 11, 1995, a final application to relicense the Pillager hydroelectric project (1.5 MW generating capability) was filed with the FERC. (See Environmental Matters - Water.) Minnesota Public Utilities Commission In November 1994 the MPUC issued an order granting the Company an overall increase in annual electric operating revenue of $19 million, or 6.4 percent, with an 11.6 percent return on equity. Effective June 1, 1995, rates for large industrial customers increased less than 4 percent, while the rate for small businesses increased 6.5 percent. The rate increases for residential customers were approved to be phased in over three years: 13.5 percent began in June 1995, 3.75 percent in January 1996, and another 3.75 percent will begin in January 1997. Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross annual electric revenue on conservation improvement programs (CIP) each year. In 1995, 1994 and 1993, the Company spent $14.2, $8 and $4.1 million, respectively, on CIP and expects to spend a total of $6.8 million during 1996. The MPUC allows such conservation expenditures in excess of amounts recovered through current rates to be accumulated in a deferred account for recovery through future rates. Since January 1994 the Company has been recovering ongoing CIP spending and $8.2 million of CIP spending from previous years. Through a billing adjustment and retail base rates approved by the MPUC, the Company is allowed to recover current and deferred CIP expenditures and the lost margin associated with power saved as a result of these programs. The Company collected $10.8 million and $7.8 million of CIP related revenue in 1995 and 1994. Minnesota law enables the Company to offer retail customers special rates to meet competition from unregulated energy suppliers or cogenerators. The Company implemented a generation deferral rate in November 1990 for Boise. In March 1994 the MPUC approved an amendment to Boise's contract which includes extension of the generation deferral rate until December 1998. While this rate is lower than the normal retail rate, it provides for recovery of approximately $20 million over the next five years of the Company's fixed costs which would not have been recovered had Boise installed its own generating facilities. In addition, special rates were implemented in 1993 to attract a new commercial customer that has a 1 MW load. Special rates were also implemented in 1995 to retain a commercial customer with a 3 MW load and in 1996 to retain another commercial customer with an 8 MW load. Public Service Commission of Wisconsin On June 16, 1995, SWL&P filed an application with the PSCW for authority to increase electric, gas and water rates. The Company requested an overall annual revenue increase of $1.3 million, or 3.2 percent, with a 12 percent return on equity. It is anticipated that the PSCW will approve a $451,000, or 1.1 percent increase, with an 11.6 percent return on equity. A final order is expected on March 29, 1996, with final rates to be effective March 30, 1996. -9-
Capital Expenditure Program Capital expenditures for the electric operations totaled $38 million during 1995, of which $7 million was for coal operations. Internally generated funds and long-term bank financing were used to fund these capital expenditures. The Company's electric generating stations have the capacity to meet customer needs through the 1990s without major capacity additions or environmental modifications. Electric operations capital expenditures are expected to be $40 million in 1996, of which $6 million is related to coal operations. Approximately $120 million of electric operations capital expenditures are expected during the period 1997 through 2000, of which $10 million is related to coal operations. The Company's estimates of such capital expenditures and the sources of financing are subject to continuing review and adjustment. Competition The competitive landscape of the electric utility industry is changing at both the wholesale and retail levels, and is affecting the way the Company strategically views the future. The enactment of the Energy Policy Act resulted in an increase in the competitive forces that affect two of the three key elements of the electric utility industry, generation and transmission. The third element, distribution, is subject to state regulation. This legislation has resulted in a more competitive market for electricity generally and particularly in wholesale markets. Wholesale In 1995 the FERC issued a Notice of Proposed Rule Making (NOPR) on Open Access Non-Discriminatory Transmission Services by Public Utilities and Transmitting Utilities and a supplemental NOPR on Recovery of Stranded Costs. The purpose of the proposed rules is to facilitate wholesale power competition, remove undue discrimination in electric transmission and set standards for recovery of stranded costs through FERC-approved rates for wholesale service. Final FERC rules are expected to be published by mid-1996. The Energy Policy Act increased competition in the wholesale market by eliminating existing legal barriers with respect to entry into the generation market and the provision of transmission services. First, the Energy Policy Act created a new class of power producers, known as Exempt Wholesale Generators (EWGs). EWGs are exempt from regulation under the Public Utility Holding Company Act of 1935 and EWG sales are generally subject to less regulation than sales by traditional utilities. The fact that EWGs may include independent power producers as well as affiliates of electric utilities marks a further diminution of the role of electric utilities as the exclusive generators of electric energy. Second, the Energy Policy Act authorized the FERC to order utilities which own or operate transmission facilities to provide wholesale transmission services to or from other utilities or entities generating electric energy for sale or resale, provided that the rates charged for transmission services are recovered from the entity seeking the transmission service and not from the transmitting utility's existing wholesale, retail or transmission customers. The Energy Policy Act expressly prohibits the FERC from ordering a utility to provide retail wheeling services to any of its customers. Regional The Company is a member of the Mid-Continent Area Power Pool (MAPP). The MAPP enhances electric service reliability, and provides the opportunity for members to enter into various wholesale power transactions and coordinate planning of new generation and transmission facilities. The MAPP membership has approved an agreement that reorganizes the power pool to establish: (1) a regional transmission group to provide comparable and efficient transmission service on a regional basis, coordinate regional transmission planning and -10-
resolve transmission service disputes; (2) a power and energy market for market-based wholesale transactions among interested participants; and (3) a generation reserve sharing pool to maintain and share generation reserves for purposes of further efficiencies. The reorganization is subject to FERC approval. Retail In 1995 the MPUC initiated an investigation into structural and regulatory issues in the electric utility industry. To make certain that delivery of electric service continues to be efficient following any restructuring, the MPUC adopted 15 principles to guide a deliberate and orderly approach to developing reasonable restructuring alternatives that ensure the fairness of a competitive market and protect the public interest. In January 1996 the MPUC established a wholesale competition working group in which company representatives will participate to initially address issues related to wholesale competition and then to consider retail competition issues including rate flexibility, innovative regulation, unbundling, safety and reliability. Large industrial and commercial customers that have the ability to own and operate their own generation facilities may compete directly with the Company to supply their own electric needs. If these facilities are Qualifying Facilities (QFs), the customers that own them may require that the Company purchase the output from them at the Company's "avoided cost" pursuant to the Public Utility Regulatory Policies Act. Additionally, these customers, as well as the balance of the Company's customers, may elect to substitute other sources of energy, such as natural gas, oil or wood, for various end uses rather than continuing to use electric energy. Municipalities may elect to serve customers of the Company lying within municipal boundaries, but must fully compensate the Company for its loss of property and revenue associated with this load. Finally, the prospect that large industrial customers might seek state authorization of retail wheeling in the future would have the effect of substantially increasing competition in the retail segment of the market for electricity. Customers Minnesota Power anticipates that its Large Power Customers will continue to aggressively seek lower energy costs through negotiations with the Company and consideration of alternative suppliers. With electric rates among the lowest in the United States and with its long-term wholesale and large power retail contracts in place, Minnesota Power believes it is well positioned to address competitive pressures. The Company remains opposed to retail wheeling because it would benefit only a few large customers while potentially adversely impacting smaller customers' rates and shareholder returns. In addition to providing electricity, the Company offers its customers a wide variety of value-added services, including conservation improvement services, to meet their energy needs. The Company also has obtained MPUC approval to offer interruptible rates to Large Power Customers. Furthermore, the Company may offer competitive rates within its service territory to serve customers that could otherwise obtain their energy needs from an unregulated energy supplier or by generating their own electricity with MPUC approval. Franchises Minnesota Power holds franchises to construct and maintain an electric distribution and transmission system in 90 cities and towns located within its service territory. SWL&P holds franchises in 15 cities and towns within its service territory. The remaining cities and towns served will not grant a franchise or do not require a franchise to operate within their boundaries. -11-
Environmental Matters The Company's electric operations are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, solid wastes, and other environmental matters. The Company considers its electric operations to be in substantial compliance with those environmental regulations currently applicable to its operations and believes all necessary permits to conduct such operations have been obtained. The Company does not currently anticipate that its potential capital expenditures for environmental matters will be material. However, because environmental laws and regulations are constantly evolving, the character, scope and ultimate costs of environmental compliance cannot be estimated. Air The Federal Clean Air Act Amendments of 1990 (Clean Air Act) require that specified fossil-fueled generating plants meet new sulfur dioxide and nitrogen oxide emission standards beginning January 1, 1995 (Phase I) and that virtually all generating plants meet more strict emission standards beginning January 1, 2000 (Phase II). None of Minnesota Power's generating facilities are covered by the Phase I requirements of the Clean Air Act. However, Phase II requirements apply to the Company's Boswell, Laskin and Hibbard plants, as well as Square Butte. The Clean Air Act creates emission allowances for sulfur dioxide based on formulas relating to the permitted 1985 emissions rate and a baseline of average fossil fuel consumed in the years 1985, 1986 and 1987. Each allowance is an authorization to emit one ton of sulfur dioxide, and each utility must have sufficient allowances to cover its annual emissions. Minnesota Power's generating facilities in Minnesota burn mainly low-sulfur western coal and Square Butte, located in North Dakota, burns lignite coal. All of these facilities are equipped with pollution control equipment such as scrubbers, baghouses or electrostatic precipitators. Phase II sulfur dioxide emission requirements are currently being met by Boswell Unit 4. Some moderate reductions in emissions may be necessary for Boswell Units 1, 2 and 3, Laskin Units 1 and 2, and Square Butte to meet the Phase II sulfur dioxide emission requirements. The Company believes it is in a good position to comply with the sulfur dioxide standards without extensive modifications. Any required reductions at the Minnesota generating facilities are expected to be achieved through the use of lower sulfur coal. Square Butte anticipates meeting any required reductions through increased use of existing scrubbers. The Clean Air Act requires the EPA to set the nitrogen oxide limitations by January 1, 1997, for Phase II generating units. To meet anticipated Phase II nitrogen oxide limitations, the Company expects to install at its plants any necessary low-nitrogen oxide burner technology by the year 2000. The total cost of compliance with the nitrogen oxide limitations for Boswell and Laskin is currently estimated to be $9 to $11 million. The costs of complying with the nitrogen oxide limitations at Hibbard and Square Butte are not determinable until regulations applicable to these plants are promulgated by the EPA. The Company is participating in a voluntary program (Climate Challenge) with the U.S. Department of Energy to identify activities that the Company has taken and additional measures that the Company may undertake on a voluntary basis that will result in limitations, reductions or sequestrations of greenhouse gas emissions by the year 2000. Section 1605 of the Energy Policy Act mandates timely and acceptable definitions of greenhouse gas accounting guidelines and greenhouse gas crediting guidelines. The Company has agreed to participate in this voluntary program provided that such participation is consistent with the Company's integrated resource planning process, does not have a material adverse effect on the Company's competitive position with respect to rates and costs, and continues to be acceptable to the Company's regulators. -12-
The costs to Minnesota Power associated with Climate Challenge participation are minor, reflecting program facilitation and voluntary reporting costs. Minnesota Power project activities to reduce, sequester or offset greenhouse gas emissions were selected because they were financially sound. Additional funds were not required to achieve greenhouse gas offsets beyond those required to facilitate projects which were justified for other applications. Water The Federal Water Pollution Control Act of 1972 (FWPCA), as amended by the Clean Water Act of 1977 and the Water Quality Act of 1987, established the National Pollutant Discharge Elimination System (NPDES) permit program. The FWPCA requires that NPDES permits be obtained from the EPA (or, when delegated, from individual state pollution control agencies) for any wastewater discharged into navigable waters. The Company has obtained all necessary NPDES permits to conduct its electric operations. Summary of National Pollutant Discharge Elimination System Permits Facility Issue Date Expiration Date - -------- ---------- --------------- Laskin December 22, 1993 October 31, 1998 Boswell February 4, 1993 December 31, 1997 Hibbard September 29, 1994 June 30, 1999 Arrowhead DC Terminal May 24, 1991 March 31, 1996 * General Office Building/ Lake Superior Plaza May 1, 1995 December 31, 1997 Square Butte July 1, 1995 June 30, 2000 - ---------------------------- * On October 2, 1995, a renewal application of this permit was submitted to the MPCA. A new permit is expected to be issued in the second quarter of 1996. Permits are extended by the timely filing of a renewal application which stays the expiration of the previously issued permit. The Company holds from the FERC licenses authorizing the ownership and operation of seven hydroelectric generating projects with a total generating capacity of 121 MW. In 1991 the Company submitted applications for new licenses for four of the projects. By orders issued in 1993, the FERC granted new licenses with terms of 30 years each, expiring December 31, 2023, for the Little Falls (4.7 MW), Sylvan (1.8 MW), and Prairie River (1.1 MW) projects. On July 13, 1995, the FERC issued to the Company a 30-year license for the St. Louis River hydroelectric project (87.6 MW), with an effective date of July 1, 1995. The Company filed a request for rehearing of the FERC's order for the purpose of challenging certain terms and conditions of the license which, if accepted by the Company, would alter the Company's operation of the project. In addition to the Company's request for rehearing, certain intervenors in the relicensing proceeding filed requests for rehearing for the purpose of obtaining other changes to the terms and conditions of the license which, if granted by the FERC, could result in further changes in the Company's operation of the project. Currently, the FERC is reviewing the requests for rehearing. An application to relicense the Pillager project (1.5 MW) was filed with the FERC on May 11, 1995. The FERC will perform an engineering, environmental and economic analysis of that application in order to determine whether to issue a new license for the project. The current license for the project expires on May 11, 1997. Should the FERC not reach a final determination to issue a new license by that date, the Company expects that the FERC will issue an annual license allowing for the continued operation of the project until the FERC issues an order disposing of the application. -13-
The two remaining hydroelectric projects, Blanchard (18 MW) and Winton (4 MW) have FERC licenses that expire in 2003. Solid Waste The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid wastes. As a result of this legislation, the EPA has promulgated various hazardous waste rules. The Company is required to notify the EPA of hazardous waste activity and routinely submits the necessary annual reports to the EPA. In response to EPA Region V's request for utilities to participate in their Great Lakes Initiative by voluntarily removing remaining polychlorinated biphenyl (PCB) inventories, the Company is scheduling replacement of PCB-contaminated oil from substation equipment by 1998 and removal of PCB capacitors by 2004. The total cost is expected to be between $1.5 and $2 million of which $200,000 was expended through December 31, 1995. The Company expects to expend about $70,000 in 1996. In 1990 the Company was notified by the EPA and the MPCA that it had been named as a potentially responsible party under the Comprehensive Environmental Response, Compensation and Liability Act pertaining to the cleanup of pollution at a northern Minnesota oil refinery site (Arrowhead Site). In 1994 a settlement was reached regarding cleanup at the Arrowhead Site. The total costs to remediate the Arrowhead Site are currently estimated at $37 million. Funding under the proposal is shared by several governmental entities and about 130 companies. Under the terms of the settlement, Minnesota Power's share of remediation costs is approximately $314,000, which has been paid. In addition, the Company has spent about $600,000 to date on legal and other costs. Remediation efforts began in 1995 and will continue in 1996 with no expected increase in costs. Mining Control and Reclamation BNI Coal's mining operations are governed by the Federal Surface Mining Control and Reclamation Act of 1977. This Act, together with the rules and regulations adopted thereunder by the Department of the Interior, Office of Surface Mining Reclamation and Enforcement (OSM), governs the approval or disapproval of all mining permits on federally owned land and the actions of the OSM in approving or disapproving state regulatory programs regulating mining activities. The North Dakota Reclamation of Strip Mined Lands Act and rules and regulations enacted thereunder in 1969, as subsequently amended by the North Dakota Mining and Reclamation Act and rules and regulations enacted thereunder in 1977, govern the reclamation of surface mined lands and are generally as stringent or more stringent than the federal rules and regulations. Compliance is monitored by the North Dakota Public Service Commission. The federal and state laws and regulations require a wide range of procedures including water management, topsoil and subsoil segregation, stockpiling and revegetation, and the posting of performance bonds to assure compliance. In general, these laws and regulations require the reclaiming of mined lands to a level of usefulness equal to or greater than that available before active mining. The Company considers BNI Coal to be in substantial compliance with those environmental regulations currently applicable to its operations and believes all necessary permits to conduct such operations have been obtained. -14-
Water Operations Water operations include SSU and Heater, both wholly owned subsidiaries of the Company. These water operations have been upgrading existing facilities, building new facilities and acquiring new systems. - SSU owns and operates water and wastewater treatment facilities in Florida. SSU is the largest private water supplier in Florida. As of December 31, 1995, SSU served 117,000 water customers and 53,000 wastewater treatment customers. In 1995 SSU acquired the assets of Orange Osceola Utilities, Inc. located near Kissimmee, Florida, for $13 million. The 17,000 water and wastewater customers acquired in this transaction offset the 15,000 customers lost with the sale of Venice Gardens' assets in December 1994. - Heater owns and operates four companies which provide water and wastewater treatment services in North Carolina and South Carolina. As of December 31, 1995, these companies served 26,000 water customers and 3,000 wastewater treatment customers. In January 1995 the town of Seabrook Island, South Carolina initiated an eminent domain action to acquire the assets of Heater's wholly owned subsidiary, Heater of Seabrook (Seabrook). A tentative agreement has been reached to sell the assets to the town for $5.9 million. Seabrook currently serves 3,000 customers. (See South Carolina Public Service Commission.) Regulatory Issues Florida Public Service Commission The following summarizes current rate proceedings with the FPSC and county commissions. - On August 2, 1995, the FPSC accepted SSU's June 1995 filing which requested an $18.1 million, or 39 percent, annual increase in water and wastewater treatment rates. On November 1, 1995, the FPSC denied SSU's original $12 million interim rate request for two reasons: (1) it was based on uniform rates which were deemed improper by a court order issued subsequent to SSU's original filing, and (2) the FPSC had not yet formulated a policy on allowable investments and expenses to be included in a forward-looking interim test year. SSU submitted additional information to support interim rate approval of $12 million based on a forward-looking test year and $8.4 million based on a historical test year. On January 4, 1996, the FPSC permitted SSU to implement an interim rate increase (based on a historical test year) of $7.9 million, on an annualized basis, over revenue previously collected under a uniform rate structure. Interim rates went into effect on January 23, 1996. Hearings with respect to the $18.1 million request are anticipated to take place beginning in April 1996 and final rates are anticipated to become effective in the fourth quarter of 1996. The primary reasons for seeking higher rates are to include in rate base for earning purposes (1) new facilities added since 1991 and (2) mandated regulatory compliance cost increases during the same period, particularly for environmental protection. The filing also includes water conservation incentives and a request for approval of a consistent policy on charges for service availability. -15-
- In connection with SSU's 1992 consolidated rate filing, the FPSC issued an order (Uniform Rates Order) in March 1993 requiring statewide uniform rates for 90 water and 37 wastewater service areas. In September 1993 rates were implemented pursuant to the Uniform Rates Order which increased SSU's revenue by $6.7 million. In October 1993 Citrus County, Florida and a customer group appealed the FPSC's Uniform Rates Order, challenging the uniform statewide rate structure. With "uniform rates," all customers in a uniform rate area pay the same rates for water and wastewater services. Uniform rates are an alternative to "stand-alone" rates which are calculated based on the cost of serving each service area. In April 1995 the Florida First District Court of Appeals reversed the Uniform Rates Order and, in October 1995 the FPSC ordered SSU to refund about $10 million (Refund Order), including interest, to customers who had paid more since September 1993 under uniform rates than they would have paid under stand-alone rates. Under the Refund Order, the collection of the $10 million from customers who paid less under uniform rates would not be permitted. Responding to a Florida Supreme Court decision addressing the issue of retroactive ratemaking and principles of equity with respect to another utility company, on March 5, 1996, the FPSC voted to reconsider the Refund Order at an unspecified date. Briefs on the reconsideration are due April 1, 1996. SSU continues to believe that it would be improper for the FPSC to order a refund to one group of customers without permitting recovery of a similar amount from the remaining customers since the First District Court of Appeals affirmed SSU's total revenue requirement for operations in Florida. No provision for refund has been recorded. In September 1993 the FPSC initiated a separate but related proceeding for the purpose of determining if, as a matter of policy, uniform statewide rates are appropriate for SSU. In September 1994 the FPSC issued an order declaring that uniform statewide rates represent good public policy. - In June 1994 the FPSC issued an order declining to issue a declaratory statement which would have acknowledged FPSC jurisdiction over SSU service areas in Hillsborough and Polk Counties. Instead the FPSC opened an investigation to determine if SSU is a single system pursuant to Florida statutes. In June 1995 the FPSC voted to assume jurisdiction over SSU facilities statewide and thus to regard SSU as a single system rather than as a utility made up of more than 150 systems. Several counties appealed this decision to the Florida District Court of Appeals. - In April 1994 the Hernando County Board of County Commissioners issued an order rescinding FPSC jurisdiction in Hernando County. In June 1994 the FPSC issued an order acknowledging that Hernando County has jurisdiction over privately-owned water and wastewater facilities located in the County as of April 5, 1994. In April 1994 SSU filed a court action before the Florida Circuit Court for Hernando County to stay the change in jurisdiction. In April 1995 the Hernando County Board of County Commissioners issued an order which, among other things, purported to require SSU to file a rate proceeding with Hernando County in June 1995. SSU amended its complaint in the Hernando County Court to include a request for stay of this County action. This court action is pending. In April 1994 SSU also requested the FPSC to retain interim jurisdiction over SSU's facilities in Hernando County until jurisdictional determinations are made by the courts. In June 1994 the FPSC issued an order denying SSU's request. SSU -16-
appealed this order to Florida's First District Court of Appeals. The Court of Appeals affirmed the FPSC's action. SSU believes that a jurisdictional change should not be made at this time because of the FPSC determination that SSU's facilities in all counties within Florida constitute a single system subject to the sole jurisdiction of the FPSC. As indicated above, several counties appealed this determination to the First District Court of Appeals. - In March 1996 the Collier County Board of County Commissioners passed a resolution and adopted an ordinance rescinding FPSC jurisdiction in Collier County. SSU's position is that Collier County cannot regulate SSU's facilities in Collier County as a result of the FPSC's "single system" determination. As indicated above, several counties, including Collier County, have appealed the FPSC's determination to the First District Court of Appeals. South Carolina Public Service Commission The following summarizes Heater's current rate proceedings with the SCPSC. - In October 1994 residents of Seabrook Island, South Carolina voted to allow the town to purchase or acquire through eminent domain powers the town's current water and wastewater treatment facilities owned by Seabrook. Seabrook currently serves 3,000 customers. In January 1995 the town of Seabrook Island initiated an eminent domain action to acquire the assets of Seabrook. In February 1995, Seabrook filed actions in South Carolina state court and federal court, challenging the town of Seabrook Island's authority to acquire these systems by eminent domain. In March 1996 a tentative agreement was reached to sell the assets to the town for $5.9 million. This sale is subject to negotiation of a definitive purchase agreement and regulatory approval. - In July 1994 Upstate Heater Utilities (Upstate), a wholly owned subsidiary of Heater, filed a request for a $71,000 annual rate increase with the SCPSC. In December 1994 the SCPSC denied the request for an annual rate increase primarily due to customer opposition. In January 1995 Upstate filed for reconsideration and the SCPSC denied the request. In February 1995 Upstate filed an appeal in the Circuit Court of South Carolina. In July 1995 the Circuit Court of South Carolina issued an order vacating the SCPSC's December 1994 order which denied Upstate's request for an annual rate increase. The case was remanded to the SCPSC for the establishment of rates which are fair and reasonable. In September 1995, the SCPSC issued a second final order granting an annual increase of $8,000. A motion for reconsideration was filed and denied in October 1995. An appeal by Upstate to the Circuit Court of South Carolina was filed in November 1995. In January 1996 the requested rates were implemented under surety bond pending the final decision of this appeal. The final decision of the appeal is expected in 1997. - In January 1994 Seabrook filed with the SCPSC a request for a $263,000 annual rate increase for operations at Seabrook Island, South Carolina. In July 1994 the SCPSC denied the request. Seabrook filed a motion for reconsideration in July 1994 maintaining that the resulting 3.98 percent return on equity was inadequate. In August 1994 the SCPSC denied reconsideration. In September 1994 Seabrook filed an appeal in the Circuit Court of South Carolina and subsequently provided notice to the customers and implemented the requested rates under surety bond in January 1995, pending the final decision on the appeal. In July 1995 the Circuit Court of South Carolina issued an order affirming the SCPSC's July 1994 order which denied -17-
Seabrook's request for an annual rate increase. An appeal to the South Carolina Supreme Court was filed in October 1995. A final decision on the appeal is expected in 1997. - In July 1992 Heater filed with the SCPSC a request for a $233,000 rate increase for operations near Columbia, South Carolina. In January 1993 the SCPSC denied the rate increase request. In March 1993 Heater filed with the Circuit Court of South Carolina an appeal of the SCPSC's denial of the request. In September 1993 the requested rates were implemented, under surety bond, pending the decision on the appeal. As a condition to the SCPSC's grant to Heater of a $110,000 annual increase in May 1994, Heater was required to cease charging the increased rates under surety bond. In October 1995 this case was heard before the South Carolina Supreme Court. In December 1995 the South Carolina Supreme Court issued an order reversing the SCPSC's January 1993 order, which denied Heater's request for an annual rate increase. The case was remanded to the SCPSC for proceedings consistent with the court opinion. In January 1996 the SCPSC ordered that a 9.28 percent operating margin was appropriate for Heater during the period in which the requested rates were charged under surety bond. The 9.28 percent operating margin equated to a total refund of $54,000, including interest, which was refunded to customers in February 1996. North Carolina Utilities Commission The following summarizes Heater's current rate proceedings with the NCUC. - In August 1995 Heater filed with the NCUC for approval of a surcharge that would allow Heater to recover $297,000 in additional testing costs required by the EPA in excess of costs included in the current rate structure. A final order is anticipated in April 1996. - In March 1995 Brookwood Water Corporation, a wholly owned subsidiary of Heater, filed with the NCUC for a $120,000 annual rate increase. In October 1995 a final order was issued granting an $85,000 annual increase. - In February 1995 Heater filed for a $314,000 annual rate increase with the NCUC. In December 1995 a final order was issued granting a $308,000 annual increase. Capital Expenditure Program Capital expenditures for the water operations totaled $34 million during 1995. Expenditures were funded with the proceeds from long-term bonds issued by SSU and internally generated funds. Capital expenditures for the Company's water operations are expected to be $25 million in 1996 for upgrades, water reuse projects and new water facilities, and to total approximately $90 million during the period 1997 through 2000. Competition The regulated water and wastewater services industry is experiencing a series of transformations including privatization, consolidation and regionalization. These new trends are a direct result of expanded environmental regulations and increasingly limited water supply and wastewater disposal options. Consequently, growth in the industry will be realized by those service providers who make adequate capital investment to achieve these transformations. -18-
Since economic regulation has not kept pace with the investment demands placed on private utilities, regulatory lag has delayed the recovery of private utilities' service costs. Historically, competition and change have been minimal in the water and wastewater industry. During the next five years, however, the Company believes that the water and wastewater industry will become more competitive and innovation-driven. The Company is focused on the application of technology to reduce costs and increase efficiency, objectives that are critical in the competitive pursuit of regulated, as well as unregulated, markets. Franchises SSU provides water and wastewater treatment services in 22 counties regulated by the FPSC, holds franchises in two counties which to date have retained authority to regulate such operations, and is contesting the jurisdiction of two other counties over SSU facilities in light of the FPSC's "single system" determination. (See Regulatory Issues - Florida Public Service Commission.) All of the water and wastewater services of Heater are under the jurisdiction of the SCPSC and the NCUC. These commissions grant franchises for Heater's service territory when the rates are authorized. Environmental Matters The Company's water operations are subject to regulation by various federal, state and local authorities in the areas of water quality, solid wastes, and other environmental matters. The Company considers its water operations to generally be in compliance with those environmental regulations currently applicable to its operations and have the permits necessary to conduct such operations. Except as noted below, the Company does not currently anticipate that its potential capital expenditures for environmental matters will be material. However, because environmental laws and regulations are constantly evolving, the character, scope and ultimate costs of environmental compliance cannot be estimated. In October 1992 the EPA issued a Request for Information to SSU regarding operations of SSU's facilities in the University Shores service area in Orange County, Florida. The request was made to obtain more details concerning exceedances of the NPDES permit for effluent quality. The requested information was compiled and sent to the EPA in late 1992 and supplemented in February 1993. In February 1993 the EPA issued a Notice to Show Cause letter to request SSU representatives to meet and discuss the exceedances. SSU met with the EPA in March 1993 and received an additional Request for Information from the EPA in April 1993. The requested information was supplied to the EPA in June 1993. At that time, SSU was attempting to determine a feasible method to eliminate surface water discharges allowed by the NPDES permit. SSU signed an agreement with Orange County Utilities (OCU) to construct an interconnect between the two collection systems so that a portion of the sewage flow at University Shores facilities could be sent to OCU. The construction of the interconnect was completed in September 1994 thereby allowing SSU to eliminate effluent discharges by the University Shores facilities to surface waters. Additional information on the project was requested by the EPA in November 1994 and SSU supplied the requested information to the EPA in December 1994. SSU has received no further communication from the EPA regarding this matter and is unable to determine what further action, if any, may be required. The interconnect with OCU, for a portion of the sewage flow, has alleviated the need for discharge of effluent to surface water. The operating permit is in the process of being renewed. -19-
In September 1993 the EPA issued an Administrative Order to SSU regarding operations of SSU's facilities in the Woodmere service area in Duval County, Florida (Woodmere facilities). The Order required monthly toxicity testing of the effluent for at least one year because of toxicity test failures during 1992 and 1993. In September 1994, because of additional 1993 and 1994 toxicity test failures at the Woodmere facilities, the EPA required implementation of a Toxicity Reduction Evaluation (TRE) plan to determine the cause of the toxicity. The TRE plan was expected to take approximately 15 months to complete. In 1995 SSU determined that the toxicity test failures were presumably due to inappropriate salt water test species. A request was filed with the EPA in February 1995 to change testing requirements to fresh water species for consistency with the FDEP wastewater permit for the Woodmere facilities, since the body of water affected is a fresh water body. A permit renewal application was filed with the FDEP in November 1995, since the permitting authority was delegated by the EPA to the FDEP in May 1995. The FDEP has responded with a request for some additional information to complete the application. The requested information was forwarded to the FDEP in February 1996. SSU representatives met with the FDEP in February 1996 and the FDEP indicated a willingness to issue a permit with fresh water test species as the requirement. This permit modification is expected to be included in the permit renewal. The EPA has retained the authority over the pending enforcement action concerning this system. SSU is unable to determine what further action, if any, may be required. In March 1995 the Administrative Order issued in August 1994 for SSU's facilities in the Beacon Hills service area in Duval County, Florida was satisfied after additional bioassay testing conducted between September 1994 and February 1995 met EPA requirements. SSU will also petition the FDEP to change test species at Beacon Hills from salt to fresh water species as requested for the Woodmere facilities. The Administrative Order has officially been closed and SSU will submit a request to the FDEP to change testing requirements during the permit renewal process. In 1995 SSU invested approximately $11.1 million of a $28.7 million annual capital expenditure budget (or approximately 39 percent) in facilities necessary to comply with environmental requirements. In 1996 SSU expects that approximately $9.6 million of the $19.5 million annual capital expenditure budget (or approximately 49 percent) will be necessary to comply with environmental requirements. Automobile Auctions Minnesota Power has an 83 percent ownership interest in ADESA, the third largest automobile auction business in the United States. ADESA, headquartered in Indianapolis, Indiana, owns and operates 19 automobile auctions in the United States and Canada through which used cars and other vehicles are sold to franchised automobile dealers and licensed used car dealers. Two wholly owned subsidiaries of ADESA, Automotive Finance Company and ADESA Auto Transport, perform related services. Sellers at ADESA's auctions include domestic and foreign auto manufacturers, car dealers, fleet/lease companies, banks and finance companies. The Company acquired 80 percent of ADESA on July 1, 1995, for $167 million in cash. Proceeds from the sale of the Company's paper and pulp business combined with proceeds from the sale of securities investments were used to fund this acquisition. Acquired goodwill and other intangible assets associated with this acquisition are being amortized on a straight line basis over periods not exceeding 40 years. In January 1996 the Company provided an additional $15 million of capital in exchange for 1,982,346 original issue common stock shares of ADESA. This capital contribution increased the Company's ownership interest in ADESA to -20-
83 percent. Put and call agreements with ADESA's four top executives provide ADESA management the right to sell to Minnesota Power, and Minnesota Power the right to purchase, ADESA management's 17 percent retained ownership interest in ADESA, in increments during the years 1997, 1998 and 1999, at a price based on ADESA's financial performance. Capital Expenditure Program Capital expenditures for automobile auction site relocation and development were $43 million for the six months ended December 31, 1995. Capital expenditures for the automobile auction business are expected to be $28 million in 1996. In September 1995 ADESA opened the world's largest indoor automobile auction facility in Framingham, Massachusetts. Expansion projects at Manville, New Jersey and Jacksonville, Florida and a relocation project in Indianapolis, Indiana began operations in the first quarter of 1996. Competition Within the automobile auction industry, ADESA's competition includes independently owned auctions as well as major chains and associations with auctions in geographic proximity to those of ADESA. ADESA competes with other auctions for a supply of automobiles to be sold by ADESA on consignment for automobile dealers, financial institutions and other sellers. ADESA also competes for a supply of rental repurchase vehicles from automobile manufacturers for auctions at factory sales. ADESA competes for these sellers of automobiles by attempting to attract a large number of dealers to purchase vehicles, which ensures competitive prices and supports the volume of vehicles auctioned, and by providing a full range of services including floorplan financing, reconditioning services which prepare automobiles for auction, transporting automobiles and the prompt processing of sale transactions. Auto auction sales for the industry are expected to rise at a rate of 6 percent to 8 percent annually. ADESA expects to participate in this industry's growth through acquisitions, greenfield start-ups and expanded services. Environmental Matters The Company's automobile auction business is subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, solid wastes, and other environmental matters. The Company considers operations of this business to be in substantial compliance with those environmental regulations currently applicable to its operations and believes all necessary permits to conduct such operations have been obtained. The Company does not currently anticipate that its potential capital expenditures for environmental matters will be material. However, because environmental laws and regulations are constantly evolving, the character, scope and ultimate costs of environmental compliance cannot be estimated. -21-
Investments The Investments segment is comprised of real estate operations, financial guaranty reinsurance and a portfolio of securities. The Company ceased operations at Reach All, the truck-mounted lifting equipment business, and sold Reach All's assets in 1995. - Real Estate Operations. The Company owns 80 percent of Lehigh, a Florida real estate company. Lehigh currently owns 4,000 acres of land and approximately 8,000 homesites near Fort Myers, Florida and 1,250 homesites in Citrus County, Florida. The real estate strategy is to acquire large residential community properties at low cost, adding value, and selling them at going market prices. - Reinsurance. Minnesota Power has a 21 percent equity investment in Capital Re. Capital Re is a Delaware holding company engaged primarily in financial and mortgage guaranty reinsurance through its wholly owned subsidiaries, Capital Reinsurance Company and Capital Mortgage Reinsurance Company. Capital Reinsurance Company is a reinsurer of financial guarantees of municipal and non-municipal debt obligations. Capital Mortgage Reinsurance Company is a reinsurer of residential mortgage guaranty insurance. The Company's equity investment in Capital Re at December 31, 1995, was $93 million. - Securities Portfolio. Minnesota Power manages a securities portfolio which is intended to provide funds for reinvestment, business acquisitions and other corporate purposes. The Company plans to continue to concentrate on market neutral strategies that provide stable and acceptable returns without sacrificing needed liquidity. Returns will continue to be partially dependent on general market yields. As of December 31, 1995, the Company had approximately $106 million invested in the securities portfolio. Environmental Matters Certain businesses included in the Company's investments segment are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, solid wastes, and other environmental matters. The Company considers these businesses to be in substantial compliance with those environmental regulations currently applicable to its operations and believes all necessary permits to conduct such operations have been obtained. The Company does not currently anticipate that its potential capital expenditures for environmental matters will be material. However, because environmental laws and regulations are constantly evolving, the character, scope and ultimate costs of environmental compliance cannot be estimated. -22-
<TABLE> Executive Officers of the Registrant <CAPTION> Initial Executive Officers Effective Date - ------------------ -------------- <S> <C> Arend J. Sandbulte, Age 62 Chairman January 22, 1996 Chairman and Chief Executive Officer May 9, 1995 Chairman, President and Chief Executive Officer May 9, 1989 Edwin L. Russell, Age 51 President and Chief Executive Officer January 22, 1996 President May 9, 1995 Robert D. Edwards, Age 51 Executive Vice President and President - MP Electric July 26, 1995 Executive Vice President and Chief Operating Officer March 1, 1993 Group Vice President - Corporate Services and Chief Financial Officer January 1, 1991 John A. Cirello, Age 52 Executive Vice President and President and Chief Executive Officer - Southern States Utilities July 24, 1995 D. Michael Hockett, Age 53 Chairman and Chief Executive Officer - ADESA July 1, 1995 Donnie R. Crandell, Age 52 Senior Vice President and President - MP Real Estate Holdings January 1, 1996 Senior Vice President - Corporate Development December 1, 1994 Retired February 28, 1994 Vice President - Corporate Development March 1, 1993 David G. Gartzke, Age 52 Senior Vice President-Finance and Chief Financial Officer December 1, 1994 Vice President - Finance and Chief Financial Officer March 1, 1993 Vice President - Finance and Treasurer January 1, 1991 Philip R. Halverson, Age 47 Vice President, General Counsel and Corporate Secretary January 1, 1996 General Counsel and Corporate Secretary March 1, 1993 General Counsel and Assistant Secretary January 23, 1991 James A. Roberts, Age 45 Vice President - Corporate Relations January 1, 1996 Geraldine R. VanTassel, Age 54 Vice President - Corporate Information Services January 1, 1996 Vice President - Corporate Resource Planning March 1, 1993 Corporate Controller June 1, 1992 Larry S. Wechter, Age 40 President, ADESA October 17, 1995 Executive Vice President, ADESA July 1, 1995 Mark A. Schober, Age 40 Corporate Controller March 1, 1993 James K. Vizanko, Age 42 Corporate Treasurer March 1, 1993 </TABLE> -23-
All of the executive officers above, except Mr. Russell, Mr. Cirello, Mr. Hockett, Mr. Crandell and Mr. Wechter, had been employed by the Company for more than five years in executive or management positions. Mr. Russell was previously Group Vice President of J. M. Huber Corporation, a $1.5 billion diversified manufacturing and natural resources company; Mr. Cirello was President of Metcalf & Eddy Services, Inc. from 1992 to 1995, responsible for $64 million in water/wastewater operation services, and before that was Vice President - Eastern Region of Chemical Waste Management; Mr. Hockett was previously Chief Executive Officer and President of ADESA and Chief Executive Officer of four auto auction companies that became subsidiaries of ADESA when it was formed in 1992; Mr. Crandell was director of business development of the Company, vice president of Topeka and vice president of business development for Topeka prior to March 1, 1993; and Mr. Wechter was previously Executive Vice President, Vice President, Chief Financial Officer and Treasurer of ADESA, and Chief Financial Officer and Treasurer of four auto auction companies that became subsidiaries of ADESA when it was formed in 1992. Prior to election to the positions shown above, the following executive officers held other positions with the Company after January 1, 1991: Mr. Halverson was director of legal services and assistant general counsel, and assistant secretary; Mr. Roberts was director of corporate relations and director of governmental relations; Ms. VanTassel was director of internal audit and leader of the organizational development team; Mr. Schober was director of internal audit; and Mr. Vizanko was director of investments and analysis, and manager of financial planning and analysis. There are no family relationships between any executive officers of the Company. All officers and directors are elected or appointed annually. The present term of office of the above executive officers extends to the first meeting of the Company's Board of Directors after the next annual meeting of shareholders. Both meetings are scheduled for May 14, 1996. -24-
Item 2. Properties. The Company had an annual and all-time record net peak load of 1,435 MW on December 13, 1995. The Company's average 1995 load factor was 83 percent. Information with respect to existing power supply sources is shown below. <TABLE> <CAPTION> Unit Year Net Winter Net Electric Power Supply No. Installed Capability Requirements - ------------ ---- --------- ---------- --------------- (MW) (MWh) (%) <S> <C> <C> <C> <C> <C> Steam Coal-Fired Boswell Energy Center near Grand Rapids, MN 1 1958 69 2 1960 69 3 1973 350 4 1980 428 ------ 916 5,723,173 46.8% ------ Laskin Energy Center Hoyt Lakes, MN 1 1953 55 2 1953 55 ------ 110 278,962 2.3 ------ ----------- ------ Total Steam 1,026 6,002,135 49.1 ------ ----------- ------ Hydro Group consisting of ten stations in MN Various 121 698,525 5.7 ------ ----------- ------ Purchased Power Square Butte burns lignite in Center, ND 333 1,950,302 16.0 All other - net - 3,574,435 29.2 ------ ----------- ------ Total Purchased Power 333 5,524,737 45.2 ------ ----------- ------ For the Year Ended December 31, 1995 1,480 12,225,397 100.0% ====== =========== ====== </TABLE> The Company has electric transmission and distribution lines of 500 kilovolts (kV) (7.8 miles), 230 kV (606.4 miles), 161 kV (42.8 miles), 138 kV (5.8 miles), 115 kV (1,239.6 miles) and less than 115 kV (6,001.3 miles). The Company owns and operates 180 substations with a total capacity of 8,545.7 megavoltamperes. Some of the transmission and distribution lines interconnect with other utilities. The Company owns and has a substantial investment in offices and service buildings, area headquarters, an energy control center, repair shops, motor vehicles, construction equipment and tools, office furniture and equipment, and leases offices and storerooms in various localities within the Company's service territory. It also owns miscellaneous parcels of real estate not presently used in electric operations. Substantially all of the electric plant of the Company is subject to the lien of its Mortgage and Deed of Trust which secures first mortgage bonds issued by the Company. The Company's properties are held by it in fee and are free from other encumbrances, subject to minor exceptions, none of which are of such a nature as to substantially impair the usefulness to the Company of such properties. Other property, including certain offices and equipment, is utilized under leases. In general, some of the electric lines are located on land not owned in fee, but are covered by necessary consents of various governmental authorities or by appropriate rights obtained from owners of private property. These consents and rights are deemed adequate for -25-
the purposes for which the properties are being used. In September 1990 the Company sold a portion of Boswell Unit 4 to WPPI. WPPI has the right to use the Company's transmission line facilities to transport its share of generation. Substantially all of the plant of SWL&P is subject to the lien of its Mortgage and Deed of Trust which secures first mortgage bonds issued by SWL&P. Substantially all of SSU's properties used in the operation of its respective water businesses are encumbered by mortgages. Approximately one-half of BNI Coal's equipment is leased under a leveraged lease agreement which expires in 2002. The remaining property and equipment are owned by BNI Coal. The MAPP membership consists of various entities located in North Dakota, South Dakota, eastern Montana, Nebraska, Iowa, Minnesota, western Wisconsin, upper Michigan, Manitoba and Saskatchewan. These entities are investor-owned utilities including the Company, rural electric generation and transmission cooperatives, public power districts, municipal electric systems, municipal organizations, and the Western Area Power Administration Billings, Montana. MAPP operates pursuant to an agreement, dated March 31, 1972, as amended, among its members. This agreement provides for the members to coordinate the installation and operation of generating plants and transmission line facilities. The MAPP membership is in the process of reorganizing. (See Item 1. Electric Operations - Competition - Regional.) Manitoba Hydro has export licenses from the National Energy Board in Calgary until November 1, 2005, to export up to 16.7 billion kilowatt-hours a year of energy and short-term firm hydroelectric power to other Canadian utilities and four utility companies in the United States, including the Company. Manitoba Hydro presently exports approximately 12 billion kilowatt-hours a year. When it is available and economical, the Company purchases energy and power from Manitoba Hydro that can be delivered through Minnesota Power's transmission lines. For information with respect to the properties of the Company's water operations see Part 1. Business - Water Operations. -26-
The following table sets forth the 19 auto auctions currently owned or leased by ADESA. Each auction has a multi-lane, drive-through auction facility, as well as additional buildings for reconditioning, registration, maintenance, body work and other ancillary and administrative services. Each auction also has secure parking areas in which it stores vehicles for auction. All automobile auction property owned by ADESA is subject to liens securing various notes payable. Year Property No. Operations Owned or Acreage Auction ADESA Auction Locations Commenced Leased Total In Use Lanes - ----------------------- ---------- -------- ----- ------ ------- United States Austin, Texas 1990 Leased 70 20 6 Birmingham, Alabama 1987 Owned 148 100 10 Buffalo, New York 1992 Owned 133 70 8 Charlotte, North Carolina 1994 Leased 56 40 8 Cincinnati-Dayton, Ohio 1986 Owned 60 40 5 Cleveland, Ohio 1994 Leased 40 40 6 Concord, Massachusetts 1947 Owned 60 60 5 Framingham, Massachusetts 1995 Leased 168 148 12 Indianapolis, Indiana 1983 Owned 70 70 8 Jacksonville, Florida 1996 Owned 90 40 6 Knoxville, Tennessee 1984 Leased 60 60 6 Lexington, Kentucky 1982 Owned 35 20 6 Memphis, Tennessee 1990 Owned 155 85 6 Miami, Florida 1994 Leased 28 28 6 Newark, New Jersey 1996 Owned 203 180 8 Sarasota/Bradenton, Florida 1990 Owned 15 15 6 Canada Montreal, Quebec 1974 Owned 70 70 6 Ottawa, Ontario 1990 Owned 65 45 5 Halifax, Nova Scotia 1993 Leased 10 10 2 The auction facilities located in Charlotte, North Carolina, Framingham, Massachusetts and Knoxville, Tennessee are leased from an unrelated third party. The leases have five year terms ending on April 1, 2000 and no renewal options. At the beginning of the fourth year of the leases, ADESA has the option to purchase the leased facilities for an aggregate of $26.5 million. In the event that ADESA does not exercise its option to purchase, it is required to guarantee any deficiency in sale proceeds the lessor realizes in disposing of the leased properties should the proceeds be less than $25,705,000. ADESA is entitled to receive any excess sales proceeds over the option price. ADESA has guaranteed the payment of principal and interest on an aggregate of $25,705,000 of the lessor's 9.82% mortgage notes payable, due August 1, 2000. ADESA's other leased auction facilities are leased pursuant to lease agreements with terms expiring through March 1, 1999. Item 3. Legal Proceedings. Material legal and regulatory proceedings are included in the discussion of the Company's business in Item 1 and are incorporated by reference herein. Item 4. Submission of Matters to a Vote of Security Holders. No matters were submitted to a vote of security holders during the fourth quarter of 1995. -27-
PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters. The Company has paid dividends without interruption on its common stock since 1948. A quarterly dividend of $.51 per share on the common stock was paid on March 1, 1996, to the holders of record on February 15, 1996. The Company's common stock is listed on The New York Stock Exchange. Dividends paid per share and the high and low prices for the Company's common stock for the periods indicated as reported by The Wall Street Journal, Midwest Edition, were as follows: Dividends Price Range Paid Per Share Quarter High Low Quarterly Annual ------- ---- --- --------- ------ 1995 - First $ 26 3/8 $ 24 1/4 $ .51 - Second 28 25 1/4 .51 - Third 28 1/8 26 3/8 .51 - Fourth 29 1/4 27 1/2 .51 $2.04 1994 - First $ 33 $ 28 $ .505 - Second 30 1/8 25 .505 - Third 28 1/8 25 .505 - Fourth 26 5/8 24 3/4 .505 $2.02 The amount and timing of dividends payable on the Company's common stock are within the sole discretion of the Company's Board of Directors. In 1995 the Company paid out 94 percent of its per share earnings in dividends. Over the longer term, the Company's goal is to reduce dividend payout to between 75 percent and 80 percent of per share earnings. This is expected to be accomplished by increasing earnings rather than reducing dividends. The Company's Articles of Incorporation, Mortgage and Deed of Trust and preferred stock purchase agreements contain provisions which under certain circumstances would restrict the payment of common stock dividends. As of December 31, 1995, no retained earnings were restricted as a result of these provisions. At March 1, 1996, there were 25,975 common stock shareholders of record. -28-
Item 6. Selected Financial Data. <TABLE> <CAPTION> 1995 1994 1993 1992 1991 ---------- ---------- ---------- ---------- ------- In thousands except per share amounts <S> <C> <C> <C> <C> <C> Operating Revenue and Income $ 672,917 $ 582,167 $ 582,495 $ 575,503 $ 587,489 Income (Loss) Continuing Operations $ 61,857 $ 59,465 $ 64,374 $67,821 $ 70,854 Discontinued Operations 2,848 1,868 (1,753) 636 4,627 -------- -------- -------- ------- -------- Before Extraordinary Item 64,705 61,333 62,621 68,457 75,481 Extraordinary Gain - - - 4,831 - -------- -------- -------- ------- -------- Net Income $ 64,705 $ 61,333 $ 62,621 $73,288 $ 75,481 Earnings Per Share Continuing Operations $ 2.06 $ 1.99 $ 2.27 $2.29 $2.31 Discontinued Operations .10 .07 (.07) .02 .15 ------ ------ ----- ------ ----- Before Extraordinary Item 2.16 2.06 2.20 2.31 2.46 Extraordinary Item - - - 0.16 - ----- ------ ------ ------ ------ Total $ 2.16 $ 2.06 $ 2.20 $2.47 $2.46 Dividends Per Share $ 2.04 $ 2.02 $ 1.98 $1.94 $1.90 Total Assets $1,947,625 $1,807,798 $1,760,526 $1,625,504 $1,586,519 Long-Term Debt $ 639,548 $ 601,317 $ 611,144 $ 541,960 $ 533,989 Redeemable Preferred Stock $ 20,000 $ 20,000 $ 20,000 $21,000 $ 24,000 </TABLE> Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. The management's discussion and analysis of financial condition and results of operations appearing on pages 14 through 20 of the Minnesota Power 1995 Annual Report are incorporated by reference in this Form 10-K Annual Report. On March 20, 1996, MP&L Capital I, a Delaware statutory business trust, all of the common interests of which are owned by the Company, issued 3,000,000 shares of 8.05% Cumulative Quarterly Income Preferred Securities. The net proceeds of $72.6 million were used to purchase Junior Subordinated Debentures of the Company. The proceeds of such purchase will be applied by the Company for general corporate purposes, which may include the acquisition of outstanding securities of the Company. Item 8. Financial Statements and Supplementary Data. The financial statements, together with the report thereon of Price Waterhouse LLP dated January 22, 1996 appearing on pages 21 through 39 of the Minnesota Power 1995 Annual Report, are incorporated by reference in this Form 10-K Annual Report. -29-
[Logo] Ernst & Young LLP One Indiana Square Phone: 317 681-7000 Suite 3400 Fax: 317 681-7216 Indianapolis, Indiana 46204-2094 Report of Independent Auditors The Board of Directors and Shareholders ADESA Corporation We have audited the consolidated balance sheet of ADESA Corporation, an 80% owned subsidiary of Minnesota Power & Light Company (MPL), as of December 31, 1995, and the related consolidated statements of income, shareholders' equity, and cash flows for the period from July 1, 1995 (date of acquisition by MPL) to December 31, 1995 (not presented separately herein). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the 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 audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of ADESA Corporation at December 31, 1995, and the consolidated results of its operations and its cash flows for the period from July 1, 1995 to December 31, 1995, in conformity with generally accepted accounting principles. ERNST & YOUNG LLP January 17, 1996, except for Note 13, as to which the date is January 19, 1996 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None. -30-
PART III Item 10. Directors and Executive Officers of the Registrant. The information required for this Item is incorporated by reference herein from the "Election of Directors" section in the Company's Proxy Statement for the 1996 Annual Meeting of Shareholders, except for information with respect to executive officers which is set forth in Part I hereof. Item 11. Executive Compensation. The information required for this Item is incorporated by reference herein from the "Compensation of Executive Officers" section in the Company's Proxy Statement for the 1996 Annual Meeting of Shareholders. Item 12. Security Ownership of Certain Beneficial Owners and Management. The information required for this Item is incorporated by reference herein from the "Security Ownership of Certain Beneficial Owners and Management" section in the Company's Proxy Statement for the 1996 Annual Meeting of Shareholders, except that the information presented in the table on page 3 of the Proxy Statement is revised with respect to the number of shares of common stock of the Company beneficially owned as of March 15, 1996, by directors, nominees for director, and executive officers as follows: <TABLE> <CAPTION> Name of Name of Beneficial Owner Shares* Beneficial Owner Shares* - ------------------------ ------ ------------------ ------ <S> <C> <C> <C> Merrill K. Cragun 3,200 Charles A. Russell 7,264 Dennis E. Evans 5,400 Edwin L. Russell 16,557 <F4> D. Michael Hockett 0 <F1> Arend J. Sandbulte 31,055 <F5> Sr. Kathleen Hofer 0 <F2> Nick Smith 1,225 Peter J. Johnson 3,840 <F3> Bruce W. Stender 1,461 Jack R. Kelly, Jr 1,500 Donald C. Wegmiller 2,891 George L. Mayer 1,000 Donnie R. Crandell 2,373 <F6> Paula F. McQueen 2,200 Robert D. Edwards 10,035 Robert S. Nickoloff 6,926 David G. Gartzke 4,734 Jack I. Rajala 8,260 Jack R. McDonald 10,219 <F7> Directors and Executive Officers as a Group (26 in Group) 144,659 - ------------------------------------------------------------------------------- * Each director, nominee for director, and executive officer owns only a fraction of 1 percent of any class of Company stock and all directors and executive officers as a group also own less than 1 percent of any class. - -------------------------------------------------------------------------------- <FN> <F1> Mr. Hockett, Director of Minnesota Power and Chairman and CEO of ADESA, holds a 15 percent ownership interest in ADESA, which links his financial interest with that of the Company. <F2> Consistent with her vows as a member of the Benedictine Order, Sr. Kathleen Hofer owns no stock of the Company. <F3> Voting and investment power for all shares is shared with his spouse. <F4> Includes 16,209 shares for which voting and investment power is shared with his spouse and 348 shares owned as custodian for his children. <F5> Includes 3,634 shares for which voting and investment power is shared with his spouse. <F6> Includes 505 shares owned by his spouse. <F7> Includes 2,420 shares owned by his spouse. </FN> </TABLE> -31-
Item 13. Certain Relationships and Related Transactions. The information required for this Item is incorporated by reference herein from the "Certain Relationships and Related Transactions" section in the Company's Proxy Statement for the 1996 Annual Meeting of Shareholders. PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. (a) Certain Documents Filed as Part of Form 10-K. (1) Financial Statements Pages in Annual Report* -------------- Minnesota Power Report of Independent Accountants 21 Consolidated Balance Sheet at December 31, 1995 and 1994 22 For the three years ended December 31, 1995 Consolidated Statement of Income 23 Consolidated Statement of Retained Earnings 23 Consolidated Statement of Cash Flows 24 Notes to Consolidated Financial Statements 25-39 - --------------------- * Incorporated by reference herein from the Minnesota Power 1995 Annual Report. Page ---- (2) Financial Statement Schedules Report of Independent Accountants on Financial Statement Schedule 37 Minnesota Power and Subsidiaries Schedule: II-Valuation and Qualifying Accounts and Reserves 38 All other schedules have been omitted either because the information is not required to be reported by the Company or because the information is included in the consolidated financial statements or the notes thereto. -32-
(3) Exhibits including those incorporated by reference Exhibit Number - ------- *2 - Agreement and Plan of Merger by and among Minnesota Power & Light Company, AC Acquisition Sub, Inc., ADESA Corporation and Certain ADESA Management Shareholders dated February 23, 1995 (filed as Exhibit 2 to Form 8-K dated March 3, 1995, File No. 1-3548). *3(a)1 - Articles of Incorporation, restated as of July 27, 1988 (filed as Exhibit 3(a), File No. 33-24936). *3(a)2 - Certificate Fixing Terms of Serial Preferred Stock A, $7.125 Series (filed as Exhibit 3(a)2, File No. 33-50143). *3(a)3 - Certificate Fixing Terms of Serial Preferred Stock A, $6.70 Series (filed as Exhibit 3(a)3, File No. 33-50143). *3(b) - Bylaws as amended January 23, 1991 (filed as Exhibit 3(b), File No. 33-45549). *4(a)1 - Mortgage and Deed of Trust, dated as of September 1, 1945, between the Company and Irving Trust Company (now The Bank of New York) and Richard H. West (W.T. Cunningham, successor), Trustees (filed as Exhibit 7(c), File No. 2-5865). *4(a)2 - Supplemental Indentures to Mortgage and Deed of Trust: Reference Number Dated as of File Exhibit ------ ----------- ---- ------- First March 1, 1949 2-7826 7(b) Second July 1, 1951 2-9036 7(c) Third March 1, 1957 2-13075 2(c) Fourth January 1, 1968 2-27794 2(c) Fifth April 1, 1971 2-39537 2(c) Sixth August 1, 1975 2-54116 2(c) Seventh September 1, 1976 2-57014 2(c) Eighth September 1, 1977 2-59690 2(c) Ninth April 1, 1978 2-60866 2(c) Tenth August 1, 1978 2-62852 2(d)2 Eleventh December 1, 1982 2-56649 4(a)3 Twelfth April 1, 1987 33-30224 4(a)3 Thirteenth March 1, 1992 33-47438 4(b) Fourteenth June 1, 1992 33-55240 4(b) Fifteenth July 1, 1992 33-55240 4(c) Sixteenth July 1, 1992 33-55240 4(d) Seventeenth February 1, 1993 33-50143 4(b) Eighteenth July 1, 1993 33-50143 4(c) -33-
Exhibit Number - ------- *4(b) - Mortgage and Deed of Trust, dated as of March 1, 1943, between Superior Water, Light and Power Company and Chemical Bank & Trust Company (Chemical Bank, successor) and Howard B. Smith (Steven F. Lasher, successor), as Trustees (filed as Exhibit 7(c), File No. 2-8668), as supplemented and modified by First Supplemental Indenture thereto dated as of March 1, 1951 (filed as Exhibit 2(d)(1), File No. 2-59690), Second Supplemental Indenture thereto dated as of March 1, 1962 (filed as Exhibit 2(d)1, File No. 2-27794), Third Supplemental Indenture thereto dated July 1, 1976 (filed as Exhibit 2(e)1, File No. 2-57478), Fourth Supplemental Indenture thereto dated as of March 1, 1985 (filed as Exhibit 4(b), File No. 2-78641) and Fifth Supplemental Indenture thereto dated as of December 1, 1992 (filed as Exhibit 4(b)1 to Form 10-K for the year ended December 31, 1992, File No. 1-3548). *4(c) - Indenture, dated as of March 1, 1993, between Southern States Utilities, Inc. and Nationsbank of Georgia, National Association, as Trustee (filed as Exhibit 4(d) to Form 10-K for the year ended December 31, 1992, File No. 1-3548). +10(a) - Minnesota Power Executive Annual Incentive Plan, effective January 1, 1996. +10(b) - Minnesota Power and Affiliated Companies Supplemental Executive Retirement Plan, as amended and restated, effective August 1, 1994. +*10(c) - Executive Investment Plan-I, as amended and restated, effective November 1, 1988 (filed as Exhibit 10(c) to Form 10-K for the year ended December 31, 1988, File No. 1-3548). +*10(d) - Executive Investment Plan-II, as amended and restated, effective November 1, 1988 (filed as Exhibit 10(d) to Form 10-K for the year ended December 31, 1988, File No. 1-3548). +*10(e) - Executive Long-Term Incentive Plan, as amended and restated, effective January 1, 1994. +*10(f) - Directors' Long-Term Incentive Plan, as amended and restated, effective January 1, 1994. +*10(g) - Deferred Compensation Trust Agreement, as amended and restated, effective January 1, 1989 (filed as Exhibit 10(f) to Form 10-K for the year ended December 31, 1988, File No. 1-3548). +*10(h) - Minnesota Power Director Stock Plan, effective January 1, 1995 (filed as Exhibit 10 to Form 10-Q for the quarter ended March 31, 1995, File No. 1-3548). 10(i) - Asset Holdings III, L.P. Note Purchase Agreement, dated as of November 22, 1994. -34-
Exhibit Number - ------- 10(j) - Lease and Development Agreement, dated as of November 28, 1994 between Asset Holdings III, L.P., as Lessor and A.D.E. of Knoxville, Inc., as Lessee. 10(k) - Lease and Development Agreement, dated as of November 28, 1994 between Asset Holdings III, L.P., as Lessor and ADESA-Charlotte, Inc., as Lessee. 10(l) - Lease and Development Agreement, dated as of December 21, 1994 between Asset Holdings III, L.P., as Lessor and Auto Dealers Exchange of Concord, Inc., as Lessee. 10(m) - Guaranty and Purchase Option Agreement between Asset Holdings III, L.P. and ADESA Corporation, dated as of November 28, 1994. 10(n) - Fourth Amended and Restated Credit Agreement, dated July 28, 1995. 10(o) - First Amendment to the Fourth Amended and Restated Credit Agreement, dated January 18, 1996. +10(p) - Employment Agreement dated May 8, 1995 between Edwin L. Russell and Minnesota Power. +10(q) - Employment Agreement dated May 1, 1995 between Robert D. Edwards and Minnesota Power. +10(r) - Employment Agreement dated February 23, 1995 between D. Michael Hockett and Minnesota Power. +10(s) - Employment Agreement dated May 1, 1995 between David G. Gartzke and Minnesota Power. +10(t) - Employment Agreement dated February 23, 1995 between Larry S. Wechter and Minnesota Power. +10(u) - Employment Agreement dated December 11, 1995 between Jack R. McDonald and Minnesota Power. +10(v) - Put and Call Agreement dated February 23, 1995 between Minnesota Power, ADESA and D. Michael Hockett, Larry S. Wechter, David H. Hill, Jerry Williams, and John E. Fuller. +10(w) - Stock Purchase Agreement dated February 23, 1995 between ADESA and D. Michael Hockett. +10(x) - Stock Purchase Agreement dated February 23, 1995 between ADESA and Larry S. Wechter. -35-
Exhibit Number - ------- 12 - Computation of Ratios of Earnings to Fixed Charges and Supplemental Ratios of Earnings to Fixed Charges. 13 - Minnesota Power 1995 Annual Report - Management's Discussion and Analysis of Financial Condition and Results of Operations, and the Company's financial statements listed in Item 14 (a)(1) of this report. *21 - Subsidiaries of the Registrant (reference is made to the Company's Form U-3A-2 for the year ended December 31, 1995, File No. 69-78). 23(a) - Consent of Independent Accountants. 23(b) - Consent of Independent Auditors. 23(c) - Consent of General Counsel. *27 - Financial Data Schedule (filed as Exhibit 27 to Form 8-K dated February 16, 1996, File No. 1-3548). - --------------------------- * Incorporated herein by reference as indicated. + Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K. (b) Reports on Form 8-K Report on Form 8-K dated and filed on January 8, 1996, with respect to Item 5. Other Events. Report on Form 8-K dated and filed on February 16, 1996, with respect to Item 7. Financial Statements and Exhibits. Report on Form 8-K dated and filed on March 11, 1996, with respect to Item 5. Other Events. -36-
Report of Independent Accountants on Financial Statement Schedule To the Board of Directors of Minnesota Power Our audits of the consolidated financial statements referred to in our report dated January 22, 1996, appearing on page 21 of the 1995 Annual Report to Shareholders of Minnesota Power (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the Financial Statement Schedule listed in Item 14(a) of this Form 10-K. In our opinion, the Financial Statement Schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. We did not audit the Financial Statements of ADESA Corporation, an 80% owned subsidiary acquired July 1, 1995, which statements reflect an allowance for estimated uncollectible trade accounts receivable of $2,418,000 at December 31, 1995 and a provision for bad debts of $2,353,000 charged to income for the six months then ended. Those statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for ADESA Corporation, is based solely on the report of the other auditors. Price Waterhouse LLP Minneapolis, Minnesota January 22, 1996 -37-
Schedule II <TABLE> Minnesota Power and Subsidiaries Valuation and Qualifying Accounts and Reserves For the Years Ended December 31, 1995, 1994 and 1993 In thousands <CAPTION> Balance at Additions Deductions Balance at Beginning Charged Other from End of of Year to Income Changes Reserves <F1> Period - ---------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> Reserve deducted from related assets Provision for uncollectible accounts 1995 Trade accounts receivable $ 1,041 $ 3,004 $ 1,453 $ 2,173 $ 3,325 Other accounts receivable 2,773 186 - 1,807 1,152 1994 Trade accounts receivable 1,565 722 116 1,362 1,041 Other accounts receivable 1,135 1,845 - 207 2,773 1993 Trade accounts receivable 1,538 492 151 616 1,565 Other accounts receivable 1,490 494 - 849 1,135 Deferred asset valuation allowance 1995 Deferred tax assets <F2> 26,878 (17,935) - - 8,943 1994 Deferred tax assets 31,475 - (4,597) - 26,878 1993 Deferred tax assets - - 31,475 - 31,475 - -------------------------- <FN> <F1> Provision for uncollectible accounts includes bad debts written off. <F2> The deferred tax asset valuation allowance was reduced by $18.4 million based on the results of a project which analyzed the economic feasibility of realizing future tax benefits available to the Company. (See Note 14.) </FN> </TABLE> -38-
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. MINNESOTA POWER & LIGHT COMPANY (Registrant) Dated: March 28, 1996 By EDWIN L. RUSSELL --------------------------------- Edwin L. Russell President and Chief Executive Officer 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 Title Date --------- ----- ---- EDWIN L. RUSSELL President, March 28, 1996 - ------------------------------ Chief Executive Officer Edwin L. Russell and Director D.G. GARTZKE Senior Vice President- March 28, 1996 - ------------------------------ Finance and D.G. Gartzke Chief Financial Officer MARK A. SCHOBER Corporate Controller March 28, 1996 - ------------------------------ Mark A. Schober -39-
Signature Title Date --------- ----- ---- MERRILL K. CRAGUN Director March 28, 1996 - ------------------------------ Merrill K. Cragun DENNIS E. EVANS Director March 28, 1996 - ------------------------------ Dennis E. Evans SISTER KATHLEEN HOFER Director March 28, 1996 - ------------------------------ Sister Kathleen Hofer D. MICHAEL HOCKETT Director March 28, 1996 - ------------------------------ D. Michael Hockett PETER J. JOHNSON Director March 28, 1996 - ------------------------------ Peter J. Johnson JACK R. KELLY, JR. Director March 28, 1996 - ------------------------------ Jack R. Kelly, Jr. PAULA F. MCQUEEN Director March 28, 1996 - ------------------------------ Paula F. McQueen ROBERT S. NICKOLOFF Director March 28, 1996 - ------------------------------ Robert S. Nickoloff JACK I. RAJALA Director March 28, 1996 - ------------------------------ Jack I. Rajala CHARLES A. RUSSELL Director March 28, 1996 - ------------------------------ Charles A. Russell AREND J. SANDBULTE Chairman and Director March 28, 1996 - ------------------------------ Arend J. Sandbulte NICK SMITH Director March 28, 1996 - ------------------------------ Nick Smith BRUCE W. STENDER Director March 28, 1996 - ------------------------------ Bruce W. Stender DONALD C. WEGMILLER Director March 28, 1996 - ------------------------------ Donald C. Wegmiller -40-