-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Tpokv+aHRgXS1vSqfl1ZGqPsmuJ5Ao2Gcx1Ma9kt4XBrqv+8xP6SUWnAaSVRaMiS Gny9e7s7Hm3CDQl/iVvQJQ== 0000067716-97-000002.txt : 19970303 0000067716-97-000002.hdr.sgml : 19970303 ACCESSION NUMBER: 0000067716-97-000002 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970228 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: MDU RESOURCES GROUP INC CENTRAL INDEX KEY: 0000067716 STANDARD INDUSTRIAL CLASSIFICATION: GAS & OTHER SERVICES COMBINED [4932] IRS NUMBER: 410423660 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03480 FILM NUMBER: 97547201 BUSINESS ADDRESS: STREET 1: 400 N FOURTH ST CITY: BISMARCK STATE: ND ZIP: 58501 BUSINESS PHONE: 7012227900 MAIL ADDRESS: STREET 1: 400 NORTH FOURTH ST CITY: BISMARCK STATE: ND ZIP: 58501 FORMER COMPANY: FORMER CONFORMED NAME: MONTANA DAKOTA UTILITIES CO DATE OF NAME CHANGE: 19850429 10-K 1 1996 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1996 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______________ to ____________ Commission file number 1-3480 MDU Resources Group, Inc. (Exact name of registrant as specified in its charter) Delaware 41-0423660 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 400 North Fourth Street 58501 Bismarck, North Dakota (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code: (701) 222-7900 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange Common Stock, par value $3.33 on which registered and Preference Share Purchase Rights New York Stock Exchange Pacific Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Preferred Stock, par value $100 (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes X . No __. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X State the aggregate market value of the voting stock held by nonaffiliates of the registrant as of February 21, 1997: $629,122,000. Indicate the number of shares outstanding of each of the Registrant's classes of common stock, as of February 21, 1997: 28,596,475 shares. DOCUMENTS INCORPORATED BY REFERENCE. 1. Pages 23 through 49 of the Annual Report to Stockholders for 1996, incorporated in Part II, Items 6 and 8 of this Report. 2. Proxy Statement, dated March 3, 1997, incorporated in Part III, Items 10, 11, 12 and 13 of this Report. CONTENTS PART I Items 1 and 2 -- Business and Properties General Montana-Dakota Utilities Co. -- Electric Generation, Transmission and Distribution Retail Natural Gas and Propane Distribution Williston Basin Interstate Pipeline Company Knife River Coal Mining Company -- Construction Materials Operations Coal Operations Consolidated Construction Materials and Mining Operations Fidelity Oil Group Item 3 -- Legal Proceedings Item 4 -- Submission of Matters to a Vote of Security Holders PART II Item 5 -- Market for the Registrant's Common Stock and Related Stockholder Matters Item 6 -- Selected Financial Data Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations Item 8 -- Financial Statements and Supplementary Data Item 9 -- Change in and Disagreements with Accountants on Accounting and Financial Disclosure PART III Item 10 -- Directors and Executive Officers of the Registrant Item 11 -- Executive Compensation Item 12 -- Security Ownership of Certain Beneficial Owners and Management Item 13 -- Certain Relationships and Related Transactions PART IV Item 14 -- Exhibits, Financial Statement Schedules and Reports on Form 8-K PART I This Form 10-K contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-K at Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Safe Harbor for Forward-Looking Statements." Forward-looking statements are all statements other than statements of historical fact, including without limitation those that are identified by the use of the words "anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions. ITEMS 1 AND 2. BUSINESS AND PROPERTIES General MDU Resources Group, Inc. (Company) is a diversified natural resource company which was incorporated under the laws of the State of Delaware in 1924. Its principal executive offices are at 400 North Fourth Street, Bismarck, North Dakota 58501, telephone (701) 222-7900. Montana-Dakota Utilities Co. (Montana-Dakota), the public utility division of the Company, provides electric and/or natural gas and propane distribution service at retail to 256 communities in North Dakota, eastern Montana, northern and western South Dakota and northern Wyoming, and owns and operates electric power generation and transmission facilities. The Company, through its wholly owned subsidiary, Centennial Energy Holdings, Inc. (Centennial), owns Williston Basin Interstate Pipeline Company (Williston Basin), Knife River Corporation (Knife River) and the Fidelity Oil Group (Fidelity Oil). Williston Basin produces natural gas and provides underground storage, transportation and gathering services through an interstate pipeline system serving Montana, North Dakota, South Dakota and Wyoming and, effective January 1, 1997, through its wholly owned subsidiary, Prairielands Energy Marketing, Inc. (Prairielands), seeks new energy markets while continuing to expand present markets for natural gas and propane. Knife River, through its wholly owned subsidiary, KRC Holdings, Inc. (KRC Holdings) and its subsidiaries, surface mines and markets aggregates and related construction materials in Oregon, California, Alaska and Hawaii. In addition, Knife River surface mines and markets low sulfur lignite coal at mines located in Montana and North Dakota. Effective February 7, 1997, Knife River Coal Mining Company changed its name to Knife River Corporation. Fidelity Oil is comprised of Fidelity Oil Co. and Fidelity Oil Holdings, Inc., which own oil and natural gas interests throughout the United States, the Gulf of Mexico and Canada through investments with several oil and natural gas producers. The significant industries within the Company's retail utility service area consist of agriculture and the related processing of agricultural products and energy-related activities such as oil and natural gas production, oil refining, coal mining and electric power generation. As of December 31, 1996, the Company had 1,867 full-time employees with 82 employed at MDU Resources Group, Inc., including Fidelity Oil, 1,041 at Montana-Dakota, 289 at Williston Basin, including Prairielands, 303 at Knife River's construction materials operations and 152 at Knife River's coal operations. Approximately 511 and 89 of the Montana-Dakota and Williston Basin employees, respectively, are represented by the International Brotherhood of Electrical Workers (IBEW). Montana-Dakota's labor contract expired on December 31, 1996, and Montana-Dakota is presently involved in labor negotiations with the IBEW. Employees subject to the collective bargaining agreement voluntarily continue to work under the terms and conditions of the expired contract. Discussions were held with the IBEW, but no agreement was reached. Current negotiations are being held through the help of federal mediation. Montana-Dakota believes these negotiations will not result in a work stoppage or have any material financial effect on its results of operations. Williston Basin's labor contract with the IBEW also expired on December 31, 1996. Negotiations with the IBEW have been concluded and Williston Basin's newly negotiated agreement through May 1999 was ratified by the affected IBEW membership effective February 3, 1997. However, the new labor agreement has not been fully executed. Knife River has a labor contract through August 1998, with the United Mine Workers of America, which represents its coal operation's hourly workforce aggregating 94 employees. In addition, Knife River has 11 labor contracts which represent 109 of its construction materials employees. The financial results and data applicable to each of the Company's business segments as well as their financing requirements are set forth in Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations". Any reference to the Company's Consolidated Financial Statements and Notes thereto shall be to the Consolidated Financial Statements and Notes thereto contained on pages 23 through 47 in the Company's Annual Report to Stockholders for 1996 (Annual Report), which are incorporated by reference herein. ENERGY DISTRIBUTION OPERATIONS AND PROPERTY (MONTANA-DAKOTA) Electric Generation, Transmission and Distribution General -- Montana-Dakota provides electric service at retail, serving nearly 113,000 residential, commercial, industrial and municipal customers located in 177 communities and adjacent rural areas as of December 31, 1996. The principal properties owned by Montana- Dakota for use in its electric operations include interests in seven electric generating stations, as further described under "System Supply and System Demand," and approximately 3,100 and 3,900 miles of transmission and distribution lines, respectively. Montana-Dakota has obtained and holds valid and existing franchises authorizing it to conduct its electric operations in all of the municipalities it serves where such franchises are required. As of December 31, 1996, Montana-Dakota's net electric plant investment approximated $281.4 million. All of Montana-Dakota's electric properties, with certain exceptions, are subject to the lien of the Indenture of Mortgage dated May 1, 1939, as supplemented, amended and restated, from the Company to The Bank of New York and W. T. Cunningham, successor trustees. The electric operations of Montana-Dakota are subject to regulation by the Federal Energy Regulatory Commission (FERC) under provisions of the Federal Power Act with respect to the transmission and sale of power at wholesale in interstate commerce, interconnections with other utilities, the issuance of securities, accounting and other matters. Retail rates, service, accounting and, in certain cases, security issuances are also subject to regulation by the North Dakota Public Service Commission (NDPSC), Montana Public Service Commission (MPSC), South Dakota Public Utilities Commission (SDPUC) and Wyoming Public Service Commission (WPSC). The percentage of Montana-Dakota's 1996 electric utility operating revenues by jurisdiction is as follows: North Dakota -- 60 percent; Montana -- 23 percent; South Dakota -- 8 percent and Wyoming -- 9 percent. System Supply and System Demand -- Through an interconnected electric system, Montana-Dakota serves markets in portions of the following states and major communities -- western North Dakota, including Bismarck, Dickinson and Williston; eastern Montana, including Glendive and Miles City; and northern South Dakota, including Mobridge. The interconnected system consists of seven on-line electric generating stations which have an aggregate turbine nameplate rating attributable to Montana- Dakota's interest of 393,488 Kilowatts (kW) and a total summer net capability of 415,408 kW. Montana-Dakota's four principal generating stations are steam-turbine generating units using coal for fuel. The nameplate rating for Montana-Dakota's ownership interest in these four stations(including interests in the Big Stone Station and the Coyote Station aggregating 22.7 percent and 25.0 percent, respectively) is 327,758 kW. The balance of Montana- Dakota's interconnected system electric generating capability is supplied by three combustion turbine peaking stations. Additionally, Montana-Dakota has contracted to purchase through October 31, 2006, up to 66,400 kW of participation power from Basin Electric Power Cooperative (Basin) for its interconnected system. The following table sets forth details applicable to the Company's electric generating stations: 1996 Net Generation Nameplate Summer (kilowatt- Generating Rating Capability hours in Station Type (kW) (kW) thousands) North Dakota -- Coyote* Steam 103,647 106,750 681,712 Heskett Steam 86,000 102,000 367,126 Williston Combustion Turbine 7,800 8,900 88 South Dakota -- Big Stone* Steam 94,111 99,558 563,862 Montana -- Lewis & Clark Steam 44,000 45,200 194,266 Glendive Combustion Turbine 34,780 31,600 14,598 Miles City Combustion Turbine 23,150 21,400 8,017 393,488 415,408 1,829,669 * Reflects Montana-Dakota's ownership interest. Virtually all of the current fuel requirements of the Coyote, Heskett and Lewis & Clark stations are met with coal supplied by Knife River under various long-term contracts. See "Construction Materials and Mining Operations and Property (Knife River) -- Coal Operations" for a discussion of a suit and arbitration filed by the Co-owners of the Coyote Station against Knife River and the Company. The majority of the Big Stone Station's fuel requirements are currently being met with coal supplied by Westmoreland Resources, Inc. under a contract which expires on December 31, 1999. During the years ended December 31, 1992, through December 31, 1996, the average cost of coal consumed, including freight, per million British thermal units (Btu) at Montana-Dakota's electric generating stations (including the Big Stone and Coyote stations) in the interconnected system and the average cost per ton, including freight, of the coal so consumed was as follows: Years Ended December 31, 1996 1995 1994 1993 1992 Average cost of coal per million Btu $.93 $.94 $.97 $.96 $.97 Average cost of coal per ton $13.64 $12.90 $12.88 $12.78 $12.79 The maximum electric peak demand experienced to date attributable to sales to retail customers on the interconnected system was 412,700 kW in August 1995. Due to a cooler than normal summer, the 1996 summer peak was only 393,300 kW. The summer peak, assuming normal weather, was previously forecasted to have been approximately 410,700 kW. Montana-Dakota's latest forecast for its interconnected system indicates that its annual peak will continue to occur during the summer and the peak demand growth rate through 2001 will approximate 1.4 percent annually. Montana-Dakota's latest forecast indicates that its kilowatt-hour (kWh) sales growth rate, on a normalized basis, through 2001 will approximate .8 percent annually. Montana-Dakota currently estimates that it has adequate capacity available through existing generating stations and long-term firm purchase contracts through the year 1999. Montana-Dakota has major interconnections with its neighboring utilities, all of which are Mid-Continent Area Power Pool (MAPP) members. Montana-Dakota considers these interconnections adequate for coordinated planning, emergency assistance, exchange of capacity and energy and power supply reliability. Through a separate electric system (Sheridan System), Montana- Dakota serves Sheridan, Wyoming and neighboring communities. The maximum peak demand experienced to date and attributable to Montana-Dakota sales to retail consumers on that system was approximately 46,600 kW and occurred in December 1983. Due to a peak shaving load management system, Montana-Dakota estimates this annual peak will not be exceeded through 1999. The Sheridan System was supplied through an interconnection with Pacific Power & Light Company under a supply contract through December 31, 1996. Beginning January 1, 1997, Black Hills Power and Light began supplying the electric power and energy for Montana-Dakota's electric service requirements for its Sheridan System under a ten-year power supply contract which allows for the purchase of up to 55,000 kW of capacity. Regulation and Competition -- The electric utility industry can be expected to continue to become increasingly competitive due to a variety of regulatory, economic and technological changes. The National Energy Policy Act of 1992 (NEPA) encourages competition by facilitating the creation of non-regulated generators. As a result of competition in electric generation, wholesale power markets have become increasingly competitive. Under NEPA, the FERC may order access to utility transmission systems by third-party energy producers on a case-by-case basis and may order electric utilities to enlarge their transmission systems to transport (wheel) power for such third parties, subject to certain conditions. To date, no third party producers are connected to Montana-Dakota's system. On April 24, 1996, the FERC issued its final rule (Order No. 888) on wholesale electric transmission open access and recovery of stranded costs. On July 8, 1996, Montana-Dakota filed proposed tariffs with the FERC in compliance with Order 888. Under the proposed tariffs, which became effective on July 9, 1996, eligible transmission service customers can choose to purchase transmission services from a variety of options ranging from full use of the transmission network on a firm long-term basis to a fully interruptible service available on an hourly basis. The proposed tariffs also include a full range of ancillary services necessary to support the transmission of energy while maintaining reliable operation of Montana-Dakota's transmission system. Montana-Dakota is awaiting final approval of the proposed tariffs by the FERC. In a related matter, on March 29, 1996, the Mid-Continent Area Power Pool (MAPP), of which Montana-Dakota is a member, filed a restated operating agreement with the FERC to provide for wholesale open access transmission on its members' systems on a non- discriminatory basis. The FERC approved MAPP's restated agreement, excluding MAPP's market-based rate proposal, effective November 1, 1996. The FERC has requested additional information from the MAPP on its market-based rate proposal before it will take further action. On December 18, 1996, Montana-Dakota filed a Request for Waiver of the requirements of FERC Order No. 889 as it relates to the Standards of Conduct. The Standards of Conduct require companies to physically separate their transmission operations/reliability functions from their marketing/merchant functions. The Request for Waiver is based on criteria established by the FERC, exempting small public utilities as defined by the United States Small Business Administration. Three of the four state public service commissions which regulate the Company's electric operations continue to evaluate utility regulations with respect to retail competition (retail wheeling). Additionally, federal legislation addressing this issue has been introduced. The MPSC, NDPSC and WPSC have initiated discussions with jurisdictional utilities on the effects retail wheeling would have on the industry and its customers. The MPSC has adopted a set of principles to guide restructuring in that state. These principles are similar to those recently adopted by the National Association of Regulatory Utility Commissioners (NARUC). The NARUC's general principle is that customers should have access to adequate, safe, reliable and efficient services at fair and reasonable prices at the lowest long-term cost to society, and structural changes in the industry should be encouraged when they result in improved economic efficiency and serve the broader public interest. The NDPSC recently asked for comments from jurisdictional utilities on the applicability of the NARUC's principles, the effects of wholesale competition, and the effects of mergers and acquisitions on the industry. The NDPSC held an informal hearing and panel discussion in December 1996, regarding these matters. Further discussions will be held on the issues surrounding retail wheeling. The WPSC will continue its study of retail wheeling during 1997, with a comprehensive review of the whole issue and its likely economic impact on the State of Wyoming. The SDPUC has not initiated any proceedings to date. Although Montana-Dakota is unable to predict the outcome of such regulatory proceedings or legislation or the extent of such competition, Montana-Dakota is continuing to take steps to effectively operate in an increasingly competitive environment. Fuel adjustment clauses contained in North Dakota and South Dakota jurisdictional electric rate schedules allow Montana-Dakota to reflect increases or decreases in fuel and purchased power costs (excluding demand charges) on a timely basis. Expedited rate filing procedures in Wyoming allow Montana-Dakota to timely reflect increases or decreases in fuel and purchased power costs as well as changes in demand and load management costs. In Montana (23 percent of electric revenues), such cost changes are includible in general rate filings. Capital Requirements -- The following schedule (in millions of dollars) summarizes the 1996 actual and 1997 through 1999 anticipated net capital expenditures applicable to Montana-Dakota's electric operations: Actual Estimated 1996 1997 1998 1999 Production $ 4.9 $ 5.2 $ 8.1 $ 9.4 Transmission 2.1 2.5 2.8 3.2 Distribution, General and Common 11.1 10.0 7.5 7.5 $18.1 $17.7 $18.4 $20.1 Environmental Matters -- Montana-Dakota's electric operations, are subject to extensive federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations and state hazard communication standards. Montana-Dakota believes it is in substantial compliance with all existing environmental regulations and permitting requirements. The U.S. Clean Air Act (Clean Air Act) requires electric generating facilities to reduce sulfur dioxide emissions by the year 2000 to a level not exceeding 1.2 pounds per million Btu. Montana-Dakota's baseload electric generating stations are coal fired. All of these stations, with the exception of the Big Stone Station, are either equipped with scrubbers or utilize an atmospheric fluidized bed combustion boiler, which permits them to operate with emission levels less than the 1.2 pounds per million Btu. The emissions requirement at the Big Stone Station is expected to be met by switching to competitively priced lower sulfur ("compliance") coal. In addition, the Clean Air Act limits the amount of nitrous oxide emissions. Montana-Dakota's generating stations, with the exception of the Big Stone Station, are within the limitations set by the United States Environmental Protection Agency (EPA). Montana-Dakota is currently unable to determine what modifications may be necessary or the costs associated with any changes which may be required at the Big Stone Station. Governmental regulations establishing environmental protection standards are continuously evolving and, therefore, the character, scope, cost and availability of the measures which will permit compliance with evolving laws or regulations, cannot now be accurately predicted. Montana-Dakota did not incur any significant environmental expenditures in 1996 and does not expect to incur any significant capital expenditures related to environmental facilities during 1997 through 1999. Retail Natural Gas and Propane Distribution General -- Montana-Dakota sells natural gas and propane at retail, serving over 200,000 residential, commercial and industrial customers located in 142 communities and adjacent rural areas as of December 31, 1996, and provides natural gas transportation services to certain customers on its system. These services are provided through a distribution system aggregating over 4,100 miles. Montana-Dakota has obtained and holds valid and existing franchises authorizing it to conduct natural gas and propane distribution operations in all of the municipalities it serves where such franchises are required. As of December 31, 1996, Montana-Dakota's net natural gas and propane distribution plant investment approximated $78.5 million. All of Montana-Dakota's natural gas distribution properties, with certain exceptions, are subject to the lien of the Indenture of Mortgage dated May 1, 1939, as supplemented, amended and restated, from the Company to The Bank of New York and W. T. Cunningham, successor trustees. The natural gas and propane distribution operations of Montana-Dakota are subject to regulation by the NDPSC, MPSC, SDPUC and WPSC regarding retail rates, service, accounting and, in certain instances, security issuances. The percentage of Montana-Dakota's 1996 natural gas and propane utility operating revenues by jurisdiction is as follows: North Dakota -- 44 percent; Montana -- 29 percent; South Dakota -- 21 percent and Wyoming -- 6 percent. System Supply, System Demand and Competition -- Montana-Dakota serves retail natural gas markets, consisting principally of residential and firm commercial space and water heating users, in portions of the following states and major communities -- North Dakota, including Bismarck, Dickinson, Williston, Minot and Jamestown; eastern Montana, including Billings, Glendive and Miles City; western and north-central South Dakota, including Rapid City, Pierre and Mobridge; and northern Wyoming, including Sheridan. These markets are highly seasonal and sales volumes depend on weather patterns. The following table reflects Montana-Dakota's natural gas and propane sales and natural gas transportation volumes during the last five years: Years Ended December 31, 1996 1995 1994 1993 1992 Mdk (thousands of decatherms) Sales: Residential 22,682 20,135 19,039 19,565 17,141 Commercial 15,325 13,509 12,403 11,196 9,256 Industrial 276 295 398 386 284 Total Sales 38,283 33,939 31,840 31,147 26,681 Transportation: Commercial 1,677 1,742 2,011 3,461 3,450 Industrial 7,746 9,349 7,267 9,243 10,292 Total Transporta- tion 9,423 11,091 9,278 12,704 13,742 Total Throughput 47,706 45,030 41,118 43,851 40,423 The restructuring of the natural gas industry, as described under "Natural Gas Transmission Operations and Property (Williston Basin)", has resulted in additional competition in retail natural gas markets. In response to these changed market conditions Montana-Dakota has established various natural gas transportation service rates for its distribution business to retain interruptible commercial and industrial load. Certain of these services include transportation under flexible rate schedules and capacity release contracts whereby Montana-Dakota's interruptible customers can avail themselves of the advantages of open access transportation on the Williston Basin system. These services have enhanced Montana- Dakota's competitive posture with alternate fuels, although certain of Montana-Dakota's customers have the potential of bypassing Montana-Dakota's distribution system by directly accessing Williston Basin's facilities. Montana-Dakota acquires all of its system requirements directly from producers, processors and marketers. Such natural gas is supplied under firm contracts, specifying market-based pricing, and is transported under firm transportation agreements by Williston Basin and Northern Gas Company and, with respect to Montana- Dakota's north-central South Dakota and south-central North Dakota markets, by South Dakota Intrastate Pipeline Company and Northern Border Pipeline Company, respectively. Montana-Dakota has also contracted with Williston Basin to provide firm storage services which enable Montana-Dakota to purchase natural gas at more uniform daily volumes throughout the year and, thus, meet winter peak requirements as well as allow it to better manage its natural gas costs. Montana-Dakota estimates that, based on supplies of natural gas currently available through its suppliers and expected to be available, it will have adequate supplies of natural gas to meet its system requirements for the next five years. Regulatory Matters -- Montana-Dakota's retail natural gas rate schedules contain clauses permitting adjustments in rates based upon changes in natural gas commodity, transportation and storage costs. Current regulatory practices allow Montana-Dakota to recover increases or refund decreases in such costs within 24 months from the time such changes occur. In June 1995, Montana-Dakota filed a general natural gas rate increase application with the MPSC requesting an increase of $2.1 million or 4.4 percent. On April 17, 1996, the MPSC issued an order in this proceeding authorizing additional annual revenues of $1.0 million, or 49 percent of the original amount requested. The rate increase became effective May 1, 1996. Capital Requirements -- Montana-Dakota's net capital expenditures aggregated $5.7 million for natural gas and propane distribution facilities in 1996 and are anticipated to be approximately $8.4 million, $7.8 million and $8.1 million in 1997, 1998 and 1999, respectively. Environmental Matters -- Montana-Dakota's natural gas and propane distribution operations are generally subject to extensive federal, state and local environmental, facility siting, zoning and planning laws and regulations. Except with regard to the issue described below, Montana-Dakota believes it is in substantial compliance with those regulations. Montana-Dakota and Williston Basin discovered polychlorinated biphenyls (PCBs) in portions of their natural gas systems and informed the EPA in January 1991. Montana-Dakota and Williston Basin believe the PCBs entered the system from a valve sealant. In January 1994, Montana-Dakota, Williston Basin and Rockwell International Corporation (Rockwell), manufacturer of the valve sealant, reached an agreement under which Rockwell has and will continue to reimburse Montana-Dakota and Williston Basin for a portion of certain remediation costs. On the basis of findings to date, Montana-Dakota and Williston Basin estimate future environmental assessment and remediation costs will aggregate $3 million to $15 million. Based on such estimated cost, the expected recovery from Rockwell and the ability of Montana-Dakota and Williston Basin to recover their portions of such costs from ratepayers, Montana-Dakota and Williston Basin believe that the ultimate costs related to these matters will not be material to each of their respective financial positions or results of operations. CENTENNIAL ENERGY HOLDINGS, INC. NATURAL GAS TRANSMISSION OPERATIONS AND PROPERTY (WILLISTON BASIN) General -- Williston Basin owns and operates over 3,600 miles of transmission, gathering and storage lines and 23 compressor stations located in the states of Montana, North Dakota, South Dakota and Wyoming. Through three underground storage fields located in Montana and Wyoming, storage services are provided to local distribution companies, producers, suppliers and others, and serve to enhance system deliverability. Williston Basin's system is strategically located near five natural gas producing basins making natural gas supplies available to Williston Basin's transportation and storage customers. In addition, Williston Basin produces natural gas from owned reserves which is sold to others or used by Williston Basin for its operating needs. Williston Basin has interconnections with seven pipelines in Wyoming, Montana and North Dakota which provide for supply and market access. At December 31, 1996, the net natural gas transmission plant investment was approximately $159.0 million. Under the Natural Gas Act (NGA), as amended, Williston Basin is subject to the jurisdiction of the FERC regarding certificate, rate and accounting matters applicable to natural gas purchases, sales, transportation, gathering and related storage operations. System Demand and Competition -- The natural gas transmission industry, although regulated, is very competitive. Beginning in the mid-1980s customers began switching their natural gas service from a bundled merchant service to transportation, and with the implementation of Order 636 which unbundled pipelines' services, this transition was accelerated. This change reflects most customers' willingness to purchase their natural gas supply from producers, processors or marketers rather than pipelines. Williston Basin competes with several pipelines for its customers' transportation business and at times will have to discount rates in an effort to retain market share. However, the strategic location of Williston Basin's system near five natural gas producing basins and the availability of underground storage and gathering services provided by Williston Basin along with interconnections with other pipelines serve to enhance Williston Basin's competitive position. Although a significant portion of Williston Basin's firm customers, including Montana-Dakota, have relatively secure residential and commercial end-users, virtually all have some price- sensitive end-users that could switch to alternate fuels. Williston Basin transports essentially all of Montana-Dakota's natural gas under firm transportation agreements, which in 1996, represented 91 percent of Williston Basin's currently subscribed firm transportation capacity. On November 7, 1996, Montana-Dakota executed a new firm transportation agreement with Williston Basin for a term of five years beginning in July 1997. Montana-Dakota's current firm transportation agreements will expire at that time. In addition, Montana-Dakota has contracted with Williston Basin to provide firm storage services to facilitate meeting Montana-Dakota's winter peak requirements. For additional information regarding Williston Basin's transportation for 1994 through 1996, see Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations". System Supply -- Williston Basin's underground storage facilities have a certificated storage capacity of approximately 353,300 million cubic feet (MMcf), including 28,900 MMcf and 46,300 MMcf of recoverable and nonrecoverable native gas, respectively. Williston Basin's storage facilities enable its customers to purchase natural gas at more uniform daily volumes throughout the year and, thus, facilitate meeting winter peak requirements. Natural gas supplies from traditional regional sources have declined during the past several years and such declines are anticipated to continue. As a result, Williston Basin anticipates that a potentially significant amount of the future supply needed to meet its customers' demands will come from non-traditional, off- system sources. Williston Basin expects to facilitate the movement of these supplies by making available its transportation and storage services. Opportunities may exist to increase transportation and storage services through system expansion or other pipeline interconnections or enhancements which could provide substantial future benefits to Williston Basin. Natural Gas Production -- Williston Basin owns in fee or holds natural gas leases and operating rights primarily applicable to the shallow rights (above 2,000 feet) in the Cedar Creek Anticline in southeastern Montana and to all rights in the Bowdoin area located in north-central Montana. Information on Williston Basin's natural gas production, average sales prices and production costs per Mcf related to its natural gas interests for 1996, 1995 and 1994 is as follows: 1996 1995 1994 Production (MMcf) 6,324 5,184 4,932 Average sales price $1.11 $0.91 $1.37 Production costs, including taxes $0.43 $0.30 $0.47 Williston Basin's gross and net productive well counts and gross and net developed and undeveloped acreage for its natural gas interests at December 31, 1996, are as follows: Gross Net Productive Wells 532 479 Developed Acreage (000's) 233 210 Undeveloped Acreage (000's) 49 44 The following table shows the results of natural gas development wells drilled and tested during 1996, 1995 and 1994: 1996 1995 1994 Productive 32 17 13 Dry Holes --- --- --- Total 32 17 13 At December 31, 1996, there was 1 well in the process of drilling. Williston Basin's recoverable proved developed and undeveloped natural gas reserves approximated 133.4 Bcf at December 31, 1996. These amounts are supported by a report dated January 31, 1997, prepared by Ralph E. Davis Associates, Inc., an independent firm of petroleum and natural gas engineers. For additional information related to Williston Basin's natural gas interests, see Note 19 of Notes to Consolidated Financial Statements. Pending Litigation -- In November 1993, the estate of W. A. Moncrief (Moncrief), a producer from whom Williston Basin purchased a portion of its natural gas supply, filed suit in Federal District Court for the District of Wyoming (Federal District Court) against Williston Basin and the Company disputing certain price and volume issues under the contract. Through the course of this action Moncrief submitted damage calculations which totalled approximately $19 million or, under its alternative pricing theory, approximately $39 million. On August 16, 1996, the Federal District Court issued its decision finding that Moncrief is entitled to damages for the difference between the price Moncrief would have received under the geographic favored-nations price clause of the contract for the period from August 13, 1993, through July 7, 1996, and the actual price received for the gas. The favored-nations price is the highest price paid from time to time under contracts in the same geographic region for natural gas of similar quantity and quality. The Federal District Court reopened the record until October 15, 1996, to receive additional briefs and exhibits on this issue. On October 15, 1996, Moncrief submitted its brief claiming damages ranging as high as $22 million under the geographic favored- nations price theory. Williston Basin, in its brief, contended that Moncrief waived its claim for a favored-nations price under an agreement with Williston Basin, and Moncrief's damage claims were calculated utilizing non-comparable contracts. Williston Basin's exhibits show Moncrief's damages should be limited to approximately $800,000 under the geographic favored-nations price theory. A hearing on all pending matters is currently scheduled for April 3, 1997. Williston Basin plans to file for recovery from ratepayers of amounts which may be ultimately due to Moncrief, if any. In December 1993, Apache Corporation (Apache) and Snyder Oil Corporation (Snyder) filed suit in North Dakota District Court, Northwest Judicial District, against Williston Basin and the Company. Apache and Snyder are oil and natural gas producers who had processing agreements with Koch Hydrocarbon Company (Koch). Williston Basin and the Company had a natural gas purchase contract with Koch. Apache and Snyder have alleged they are entitled to damages for the breach of Williston Basin's and the Company's contract with Koch. Williston Basin and the Company believe that if Apache and Snyder have any legal claims, such claims are with Koch, not with Williston Basin or the Company. Williston Basin, the Company and Koch have settled their disputes. Apache and Snyder have recently provided alleged damages under differing theories ranging up to $8.2 million without interest. A motion to intervene in the case by several other producers, all of whom had contracts with Koch but not with Williston Basin, was denied on December 13, 1996. Trial on this matter is scheduled for September 8, 1997. The claims of Apache and Snyder, in Williston Basin's opinion, are without merit and overstated. If any amounts are ultimately found to be due Apache and Snyder, Williston Basin plans to file for recovery from ratepayers. On July 18, 1996, Jack J. Grynberg (Grynberg) filed suit in United States District Court for the District of Columbia against Williston Basin and over 70 other natural gas pipeline companies. Grynberg, acting on behalf of the United States under the False Claims Act, is alleging improper measurement of the heating content or volume of natural gas purchased by the defendants resulting in the underpayment of royalties to the United States. The United States government, particularly officials from the Departments of Justice and Interior, reviewed the complaint and the evidence presented by Grynberg and declined to intervene in the action, permitting Grynberg to proceed on his own. Williston Basin believes Grynberg's claims are without merit and intends to vigorously contest this suit. Regulatory Matters and Revenues Subject to Refund -- Williston Basin has pending with the FERC two general natural gas rate change applications implemented in 1992 and 1996. In July 1995, the FERC issued an order relating to Williston Basin's 1992 rate change application. In August 1995, Williston Basin filed, under protest, tariff sheets in compliance with the FERC's order, with rates which went into effect on September 1, 1995. Williston Basin requested rehearing of certain issues addressed in the order. On July 19, 1996, the FERC issued an order granting in part and denying in part Williston Basin's rehearing request. A hearing was held on August 29, 1996, and this matter is currently pending before the FERC. In addition, Williston Basin has appealed certain issues contained in the FERC's orders to the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit Court). In June 1995, Williston Basin filed a general rate increase application with the FERC. As a result of FERC orders issued after Williston Basin's application was filed, in December 1995, Williston Basin filed revised base rates with the FERC resulting in an increase of $8.9 million or 19.1 percent over the currently effective rates. Williston Basin began collecting such increase effective January 1, 1996, subject to refund. On February 3, 1997, Williston Basin filed briefs with the D.C. Circuit Court related to its appeal of orders which had been received from the FERC beginning in May 1993, regarding the appropriate selling price of certain natural gas in underground storage which was determined to be excess upon Williston Basin's implementation of Order 636. The FERC ordered that the gas be offered for sale to Williston Basin's customers at its original cost. Williston Basin requested rehearing of this matter on the grounds that the FERC's order constituted a confiscation of its assets, which request was subsequently denied by the FERC. Williston Basin believes that it should be allowed to sell this natural gas at its fair value and retain any profits resulting from such sales since its ratepayers had never paid for the natural gas. Oral arguments on this matter before the D.C. Circuit Court are scheduled for May 9, 1997. Reserves have been provided for a portion of the revenues that have been collected subject to refund with respect to pending regulatory proceedings and for the recovery of certain producer settlement buy-out/buy-down costs to reflect future resolution of certain issues with the FERC. Williston Basin believes that such reserves are adequate based on its assessment of the ultimate outcome of the various proceedings. Natural Gas Repurchase Commitment -- The Company has offered for sale since 1984 the inventoried natural gas available under a repurchase commitment with Frontier Gas Storage Company, as described in Note 3 of Notes to Consolidated Financial Statements. As a part of the corporate realignment effected January 1, 1985, the Company agreed, pursuant to the Settlement approved by the FERC, to remove from rates the financing costs associated with this natural gas. In January 1986, because of the uncertainty as to when a sale would be made, Williston Basin began charging the financing costs associated with this repurchase commitment to operations as incurred. Such costs, consisting principally of interest and related financing fees, approximated $5.7 million, $6.0 million and $4.6 million in 1996, 1995 and 1994, respectively. The FERC has issued orders that have held that storage costs should be allocated to this gas, prospectively beginning May 1992, as opposed to being included in rates applicable to Williston Basin's customers. These storage costs, as initially allocated to the Frontier gas, approximated $2.1 million annually, for which Williston Basin has provided reserves. Williston Basin appealed these orders to the D.C. Circuit Court. On December 26, 1996, the D.C. Circuit Court issued its order ruling that the FERC's actions in allocating costs to the Frontier gas were appropriate. Williston Basin is awaiting a final order from the FERC. Beginning in October 1992, as a result of prevailing natural gas prices, Williston Basin began to sell and transport a portion of the natural gas held under the repurchase commitment. Through the second quarter of 1996, 17.8 MMdk of this natural gas had been sold. However, in the third quarter of 1996, Williston Basin, based on a number of factors including differences in regional natural gas prices and natural gas sales occurring at that time, wrote down the remaining 43.0 MMdk of this gas to its then current market value. The value of this gas was determined using the sum of discounted cash flows of expected future sales occurring at then current regional natural gas prices as adjusted for anticipated future price increases. This resulted in a write-down aggregating $18.6 million ($11.4 million after tax). In addition, Williston Basin wrote off certain other costs related to this natural gas of approximately $2.5 million ($1.5 million after tax). The amounts related to this write-down are included in "Costs on natural gas repurchase commitment" in the Consolidated Statements of Income. The recognition of the then current market value of this natural gas facilitated the sale by Williston Basin of 10.4 MMdk from the date of the write-down through December 31, 1996, and should allow Williston Basin to market the remaining 32.5 MMdk on a sustained basis enabling Williston Basin to liquidate this asset over approximately the next five years. Other Information -- In December 1994, the United States Minerals Management Service (MMS) directed Williston Basin to pay approximately $1.9 million, plus interest, in claimed royalty underpayments. These royalties are attributable to natural gas production by Williston Basin from federal leases in Montana and North Dakota for the period March 1, 1988, through December 31, 1991. This matter is currently on appeal with the MMS. In December 1993, Williston Basin received from the Montana Department of Revenue (MDR) an assessment claiming additional production taxes due of $3.7 million, plus interest, for 1988 through 1991 production. These claimed taxes result from the MDR's belief that certain natural gas production during the period at issue was not properly valued. Williston Basin does not agree with the MDR and has reached an agreement with the MDR that the appeal process be held in abeyance pending further review. Capital Requirements -- The following schedule (in millions of dollars) summarizes the 1996 actual and 1997 through 1999 anticipated net capital expenditures applicable to Williston Basin's operations: Actual Estimated 1996 1997 1998 1999 Production and Gathering $---* $ 4.5 $ 6.7 $13.0 Underground Storage .1 .4 1.0 1.4 Transmission 3.2 5.4 4.2 10.9 General and Other 1.7 2.2** 1.7** 4.7** $5.0 $12.5 $13.6 $30.0 * Net of $5.1 million in preferred stock and cash received from the sale of 208 miles of underutilized gathering lines and related facilities to Interenergy Corporation. ** Includes net capital expenditures for Prairielands. Environmental Matters -- Williston Basin's interstate natural gas transmission operations are generally subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations. Except as may be found with regard to the issues described below, Williston Basin believes it is in substantial compliance with those regulations. See "Environmental Matters" under "Montana-Dakota -- Retail Natural Gas and Propane Distribution" for a discussion of PCBs contained in Montana-Dakota's and Williston Basin's natural gas systems. CONSTRUCTION MATERIALS AND MINING OPERATIONS AND PROPERTY (KNIFE RIVER) Construction Materials Operations: General -- Knife River, through KRC Holdings, operates construction materials and mining businesses in the Anchorage, Alaska area, north and north-central California, southern Oregon and the Hawaiian Islands. These operations produce and sell construction aggregates (sand and gravel) and supply ready-mixed concrete for use in most types of construction including homes, schools, shopping centers, office buildings and industrial parks as well as roads, freeways and bridges. In addition, the Alaskan, northern California and Oregon operations produce and sell asphalt for various commercial and roadway applications. Although not common to all locations, other products include the manufacture and/or sale of cement, various finished concrete products and other building materials and related construction services. In April 1996, KRC Holdings purchased Baldwin Contracting Company, Inc. (Baldwin) of Chico, California. Baldwin is a major supplier of aggregate, asphalt and construction services in the northern Sacramento Valley and adjacent Sierra Nevada Mountains of northern California. Baldwin also provides a variety of construction services, primarily earth moving, grading, road and highway construction and maintenance. In June 1996, KRC Holdings purchased the assets of Medford Ready-Mix Concrete, Inc. (Medford) located in Medford, Oregon. The acquired company serves the residential and small commercial construction market with ready-mixed concrete and aggregates. For information regarding sales volumes and revenues for the construction materials operations for 1994 through 1996, see Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations." Competition -- Knife River's construction materials products are marketed under highly competitive conditions. Since there are generally no measurable product differences in the market areas in which Knife River conducts its construction materials businesses, price is the principal competitive force these products are subject to, with service, delivery time and proximity to the customer also being significant factors. The number and size of competitors varies in each of Knife River's principal market areas and product lines. The demand for construction materials products is significantly influenced by the cyclical nature of the construction industry in general. The key economic factors affecting product demand are changes in the level of local, state and federal governmental spending, general economic conditions within the market area which influences both the commercial and private sectors, and prevailing interest rates. Knife River is not dependent on any single customer or group of customers for sales of its construction materials products, the loss of which would have a materially adverse affect on its construction materials businesses. During 1994, 1995 and 1996, no single customer accounted for more than 10 percent of annual construction materials revenues. Coal Operations: General -- Knife River is engaged in lignite coal mining operations. Knife River's surface mining operations are located at Beulah, North Dakota and Savage, Montana. The average annual production from the Beulah and Savage mines approximates 2.6 million and 300,000 tons, respectively. Reserve estimates related to these mine locations are discussed herein. During the last five years, Knife River mined and sold the following amounts of lignite coal: Years Ended December 31, 1996 1995 1994 1993 1992 (In thousands) Tons sold: Montana-Dakota generating stations 528 453 691 624 521 Jointly-owned generating stations-- Montana-Dakota's share 565 883 1,049 1,034 1,021 Others 1,695 2,767 3,358 3,299 3,259 Industrial and other sales 111 115 108 109 112 Total 2,899 4,218 5,206 5,066 4,913 Revenues $32,696 $39,956 $45,634 $44,230 $43,770 In recent years, in response to competitive pressures from other mines, Knife River has reduced its coal prices and/or not passed through cost increases which are allowed under its contracts. Although Knife River has contracts in place specifying the selling price of coal, these price concessions are being made in an effort to remain competitive and maximize sales. In November 1995, a suit was filed in District Court, County of Burleigh, State of North Dakota (State District Court) by Minnkota Power Cooperative, Inc., Otter Tail Power Company, Northwestern Public Service Company and Northern Municipal Power Agency (Co- owners), the owners of an aggregate 75 percent interest in the Coyote Station, against the Company and Knife River. In its complaint, the Co-owners alleged a breach of contract against Knife River of the long-term coal supply agreement (Agreement) between the owners of the Coyote Station and Knife River. The Co-owners have requested a determination by the State District Court of the pricing mechanism to be applied to the Agreement and have further requested damages during the term of such alleged breach on the difference between the prices charged by Knife River and the prices as may ultimately be determined by the State District Court. The Co-owners also alleged a breach of fiduciary duties by the Company as operating agent of the Coyote Station, asserting essentially that the Company was unable to cause Knife River to reduce its coal price sufficiently under the Agreement, and are seeking damages in an unspecified amount. On January 8, 1996, the Company and Knife River filed separate motions with the State District Court to dismiss or stay pending arbitration. On May 6, 1996, the State District Court granted the Company's and Knife River's motions and stayed the suit filed by the Co-owners pending arbitration, as provided for in the Agreement. On September 12, 1996, the Co-owners notified the Company and Knife River of their demand for arbitration of the pricing dispute that had arisen under the Agreement. The demand for arbitration, filed with the American Arbitration Association (AAA), did not make any direct claim against the Company in its capacity as operator of the Coyote Station. The Co-owners requested that the arbitrators make a determination that the pricing dispute is not a proper subject for arbitration. In the alternative, the Co-owners requested the arbitrators to make a determination that the prices charged by Knife River were excessive and that the Co-owners should be awarded damages based upon the difference between the prices that Knife River charged and a "fair and equitable" price, approximately $50 million or more. Upon application by the Company and Knife River, the AAA administratively determined that the Company was not a proper party defendant to the arbitration, and the arbitration is proceeding against Knife River. Although unable to predict the outcome of the arbitration, Knife River and the Company believe that the Co-owners claims are without merit and intend to vigorously defend the prices charged pursuant to the Agreement. Knife River does not anticipate any significant growth in its lignite coal operations in the near future due to competition from coal and other alternate fuel sources. Limited growth opportunities may be available to Knife River's lignite coal operations through the continued evaluation and pursuit of niche markets such as agricultural products processing facilities. Consolidated Construction Materials and Mining Operations: Capital Requirements -- The following schedule (in millions of dollars) summarizes the 1996 actual, including the amounts related to the acquisition of Baldwin and Medford, and 1997 (including amounts related to anticipated acquisitions) through 1999 anticipated net capital expenditures applicable to Knife River's consolidated construction materials and mining operations: Actual Estimated 1996 1997 1998 1999 Construction Materials $22.2 $31.1 $ 9.4 $ 6.6 Coal 1.9 4.3 4.6 4.5 $24.1 $35.4 $14.0 $11.1 Knife River continues to seek additional growth opportunities. These include investigating the acquisition of other surface mining properties, particularly those relating to sand and gravel aggregates and related products such as ready-mixed concrete, asphalt and various finished aggregate products. Environmental Matters -- Knife River's construction materials and mining operations are subject to regulation customary for surface mining operations, including federal, state and local environmental and reclamation regulations. Except as may be found with regard to the issue described below, Knife River believes it is in substantial compliance with those regulations. In September 1995, Unitek Environmental Services, Inc. and Unitek Solvent Services, Inc. (Unitek) filed a complaint against Hawaiian Cement in the United States District Court for the District of Hawaii (District Court) alleging that dust emissions from Hawaiian Cement's cement manufacturing plant at Kapolei, Hawaii (Plant) violated the Hawaii State Implementation Plan (SIP) of the Clean Air Act, constituted a continual nuisance and trespass on the plaintiff's property, and that Hawaiian Cement's conduct warranted the payment of punitive damages. Hawaiian Cement is a Hawaiian general partnership whose general partners (with joint and several liability) are Knife River Hawaii, Inc., an indirect wholly owned subsidiary of the Company, and Adelaide Brighton Cement (Hawaii), Inc. Unitek is seeking civil penalties under the Clean Air Act (as described below), and had sought damages for various claims (as described above) of up to $20 million in the aggregate. On August 7, 1996, the District Court issued an order granting Plaintiffs' motion for partial summary judgment relating to the Clean Air Act, indicating that it would issue an injunction shortly. The issue of civil penalties under the Clean Air Act was reserved for further hearing at a later date, and Unitek's claims for damages were not addressed by the District Court at such time. On September 16, 1996, Unitek and Hawaiian Cement reached a settlement which resolved all claims relating to the $20 million in damages that Unitek had previously sought. However, the settlement did not resolve the matter regarding the civil penalties sought by Unitek relating to the alleged violations by Hawaiian Cement of the Clean Air Act nor did it affect the EPA's Notice of Violation (NOV) as discussed below. Based on a joint petition filed by Unitek and Hawaiian Cement, the District Court stayed the proceeding and the issuance of an injunction while the parties continue to negotiate the remaining Clean Air Act claims. On May 7, 1996, the EPA issued a NOV to Hawaiian Cement. The NOV states that dust emissions from the Plant violated the SIP. Under the Clean Air Act, the EPA has the authority to issue an order requiring compliance with the SIP, issue an administrative order requiring the payment of penalties of up to $25,000 per day per violation (not to exceed $200,000), or bring a civil action for penalties of not more than $25,000 per day per violation and/or bring a civil action for injunctive relief. It is also possible that the EPA could elect to join the suit filed by Unitek. Depending upon the specific actions that may ultimately be taken by either the EPA or the District Court, Hawaiian Cement is likely to have to modify its operations at its cement manufacturing facility. Hawaiian Cement has met with the EPA and settlement discussions are currently ongoing. Although no assurance can be provided, the Company does not believe that the total cost of any modifications to the facility, the level of civil penalties which may ultimately be assessed or settlement costs, will have a material effect on the Company's results of operations. Reserve Information -- As of December 31, 1996, the combined construction materials operations had under ownership approximately 120 million tons of recoverable aggregate reserves. As of December 31, 1996, Knife River had under ownership or lease, reserves of approximately 229 million tons of recoverable lignite coal, 89 million tons of which are at present mining locations. Such reserve estimates were prepared by Weir International Mining Consultants, independent mining engineers and geologists, in a report dated May 9, 1994, and have been adjusted for 1994 through 1996 production. Knife River estimates that approximately 67 million tons of its reserves will be needed to supply Montana-Dakota's Coyote, Heskett and Lewis & Clark stations for the expected lives of those stations and to fulfill the existing commitments of Knife River for sales to third parties. OIL AND NATURAL GAS OPERATIONS AND PROPERTY (FIDELITY OIL) General -- Fidelity Oil is involved in the acquisition, exploration, development and production of oil and natural gas properties. Fidelity Oil's operations vary from the acquisition of producing properties with potential development opportunities to exploration and are located throughout the United States, the Gulf of Mexico and Canada. Fidelity Oil shares revenues and expenses from the development of specified properties in proportion to its interests. Operating Information -- Information on Fidelity Oil's oil and natural gas production, average sales prices and production costs per net equivalent barrel related to its oil and natural gas interests for 1996, 1995 and 1994 are as follows: 1996 1995 1994 Oil: Production (000's of barrels) 2,149 1,973 1,565 Average sales price $17.91 $15.07 $13.14 Natural Gas: Production (MMcf) 14,067 12,319 9,228 Average sales price $2.09 $1.51 $1.84 Production costs, including taxes, per net equivalent barrel $3.31 $3.18 $4.04 Well and Acreage Information -- Fidelity Oil's gross and net productive well counts and gross and net developed and undeveloped acreage related to its interests at December 31, 1996, are as follows: Gross Net Productive Wells: Oil 2,712 148 Natural Gas 491 28 Total 3,203 176 Developed Acreage (000's) 702 65 Undeveloped Acreage (000's) 947 73 Exploratory and Development Wells -- The following table shows the results of oil and natural gas wells drilled and tested during 1996, 1995 and 1994: Net Exploratory Net Development Productive Dry Holes Total Productive Dry Holes Total Total 1996 1 2 3 4 0 4 7 1995 3 2 5 8 1 9 14 1994 4 3 7 6 1 7 14 At December 31, 1996, there were three development wells and no exploratory wells in the process of drilling. Capital Requirements -- The following summary (in millions of dollars) reflects net capital expenditures, including those not subject to amortization, related to oil and natural gas activities for the years 1996, 1995 and 1994: 1996 1995 1994 Acquisitions $23.2 $ 9.1 $ 3.2 Exploration 8.1 7.7 12.6 Development 15.9 22.2 18.8 Net Capital Expenditures $47.2 $39.0 $34.6 Fidelity Oil's net capital expenditures are anticipated to be approximately $50 million for both 1997 and 1998 and $55 million for 1999. Reserve Information -- Fidelity Oil's recoverable proved developed and undeveloped oil and natural gas reserves approximated 16.1 million barrels and 66.8 Bcf, respectively, at December 31, 1996. Of these amounts, 9.3 million barrels and 2.2 Bcf, as supported by a report dated January 9, 1997, prepared by Ralph E. Davis Associates, Inc., an independent firm of petroleum and natural gas engineers, were related to its properties located in the Cedar Creek Anticline in southeastern Montana. For additional information related to Fidelity Oil's oil and natural gas interests, see Note 19 of Notes to Consolidated Financial Statements. ITEM 3. LEGAL PROCEEDINGS Williston Basin -- Williston Basin has been named as a defendant in a legal action primarily related to certain natural gas price and volume issues. Such suit was filed by Moncrief. In addition, Williston Basin has been named as a defendant in a legal action related to a natural gas purchase contract. Such suit was filed by Apache and Snyder. Also, Williston Basin and over 70 other natural gas pipeline companies have been named as defendants in a legal action related to measurement of the heating content or volume of natural gas purchased by the defendants. Such suit was filed by Grynberg. The above legal actions are described under Items 1 and 2 -- "Business and Properties -- Natural Gas Transmission Operations and Property (Williston Basin)." The Company's assessment of the proceedings are included in the respective descriptions of the litigation. Knife River -- The Company and Knife River have been named as defendants in a legal action primarily related to coal pricing issues at the Coyote Station. The suit has been stayed by the State District Court pending arbitration. Such suit was filed by the Co-owners of the Coyote Station. Hawaiian Cement has been named as a defendant in a legal action primarily related to dust emissions from Hawaiian Cement's cement manufacturing plant at Kapolei, Hawaii. Such suit was filed by Unitek. In addition, the EPA has issued a NOV to Hawaiian Cement. The above legal actions are described under Items 1 and 2 -- "Business and Properties -- Construction Materials and Mining Operations and Property (Knife River)." The Company's assessment of the proceedings is included in the respective descriptions of the litigation. 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 1996. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS The Company's common stock is listed on the New York Stock Exchange and the Pacific Stock Exchange under the symbol "MDU". The price range of the Company's common stock as reported by The Wall Street Journal composite tape during 1996 and 1995 and dividends declared thereon were as follows: Common Common Common Stock Stock Price Stock Price Dividends (High) (Low) Per Share 1996 First Quarter $23.00 $19.88 $0.2725 Second Quarter 23.50 20.13 0.2725 Third Quarter 22.38 20.75 0.2775 Fourth Quarter 23.38 21.25 0.2775 $1.1000 1995* First Quarter $18.67 $17.17 $0.2666 Second Quarter 20.00 17.75 0.2666 Third Quarter 21.33 19.08 0.2725 Fourth Quarter 23.08 19.63 0.2725 $1.0782 _______________________ * Adjusted for October 1995 three-for-two common stock split. As of December 31, 1996, the Company's common stock was held by over 14,600 stockholders. ITEM 6. SELECTED FINANCIAL DATA Reference is made to Selected Financial Data on pages 48 and 49 of the Company's Annual Report which is incorporated herein by reference. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview The following table (in millions of dollars) summarizes the contribution to consolidated earnings by each of the Company's businesses. Years ended December 31, Business 1996 1995 1994 Electric $ 11.4 $ 12.0 $ 11.7 Natural gas distribution 4.9 1.6 .3 Natural gas transmission 2.5 8.4 6.1 Construction materials and mining 11.5 10.8 11.6 Oil and natural gas production 14.4 8.0 9.3 Earnings on common stock $ 44.7 $ 40.8 $ 39.0 Earnings per common share $ 1.57 $ 1.43 $ 1.37 Return on average common equity 13.0% 12.3% 12.1% Earnings for 1996 increased $3.9 million from the comparable period a year ago due primarily to higher oil and natural gas production and prices at the oil and natural gas production businesses. Increased retail sales at the electric and natural gas distribution businesses, primarily the result of 14 percent colder weather than the comparable period a year ago, also added to the increase in earnings. Increased transportation of natural gas held under the repurchase commitment and increased volumes transported to storage, combined with the benefits of a favorable rate change implemented in January 1996, at the natural gas transmission business further improved earnings. In addition, earnings from Baldwin and Hawaiian Cement, businesses acquired in April 1996, and September 1995, respectively, contributed to the earnings increase. The write-down to the then current market price of the natural gas available under the repurchase commitment partially offset the earnings increase. The write-down, which approximated $21.1 million, or $12.9 million after tax, was significantly offset by the reversal of certain reserves for tax and other contingencies at the natural gas transmission and oil and natural gas production businesses, aggregating $7.4 million and $1.8 million after tax, respectively. The net effect of these items resulted in a $3.7 million, or 13 cent per common share, net charge to earnings for the year. Also somewhat offsetting the earnings improvement was the nonrecurring effect of a favorable FERC order received in April 1995. The order allowed for the one-time billing of customers for $2.2 million after tax, including interest, to recover a portion of the amount previously refunded in July 1994. In addition, increased purchased power demand charges at the electric business and increased operating costs at the electric, natural gas transmission and oil and natural gas production businesses partially offset the earnings improvement. Higher interest expense at the construction materials and mining and oil and natural gas production businesses also somewhat offset the earnings increase. The effects of lower coal sales to the Big Stone Station due to the expiration of the coal contract in August 1995 and the resulting closure of the Gascoyne mine also partially offset the earnings improvement. Earnings for 1995 increased $1.8 million from the comparable period a year earlier due primarily to increased retail sales at the electric business and increased throughput at the natural gas distribution and natural gas transmission businesses. Increased oil prices and oil and natural gas production at the oil and natural gas production business combined with the benefits derived from favorable rate changes at the natural gas distribution and transmission businesses also increased earnings. The favorable rate change at the natural gas transmission business resulted from the previously described FERC order received in April 1995 on a rehearing request relating to a 1989 general rate proceeding. Income from Hawaiian Cement also contributed to the earnings increase. 1994 earnings included the benefit of a $4.5 million gain (after tax) realized on the sale of an equity investment in General Atlantic Resources, Inc. (GARI). Additionally, the effects of decreased natural gas prices at the natural gas transmission and oil and natural gas production businesses, lower coal sales to the Big Stone Station due to the expiration of a coal contract in August 1995, and increased costs associated with rainy West Coast weather at the construction materials operations partially offset the earnings increase. ________________________________ Reference should be made to Items 1 and 2 -- "Business and Properties" and Notes to Consolidated Financial Statements for information pertinent to various commitments and contingencies. Financial and operating data The following tables (in millions, where applicable) are key financial and operating statistics for each of the Company's business units. Montana-Dakota -- Electric Operations Years ended December 31, 1996 1995 1994 Operating revenues: Retail sales $128.8 $ 124.4 $ 123.2 Sales for resale and other 10.0 10.2 10.7 138.8 134.6 133.9 Operating expenses: Fuel and purchased power 44.0 41.8 43.2 Operation and maintenance 41.4 40.1 41.0 Depreciation, depletion and amortization 17.1 16.3 15.5 Taxes, other than income 6.8 6.5 6.6 109.3 104.7 106.3 Operating income 29.5 29.9 27.6 Retail sales (kWh) 2,067.9 1,993.7 1,955.1 Sales for resale (kWh) 374.6 408.0 444.5 Average cost of fuel and purchased power per kWh $ .017 $ .016 $ .017 Montana-Dakota -- Natural Gas Distribution Operations Years ended December 31, 1996 1995 1994 Operating revenues: Sales $151.5 $ 146.8 $ 151.7 Transportation and other 3.5 3.7 3.6 155.0 150.5 155.3 Operating expenses: Purchased natural gas sold 102.7 102.6 111.3 Operation and maintenance 30.0 30.4 30.0 Depreciation, depletion and amortization 6.9 6.7 6.1 Taxes, other than income 3.9 3.9 4.0 143.5 143.6 151.4 Operating income 11.5 6.9 3.9 Volumes (dk): Sales 38.3 33.9 31.8 Transportation 9.4 11.1 9.3 Total throughput 47.7 45.0 41.1 Degree days (% of normal) 116.2% 101.6% 96.7% Average cost of natural gas, including transportation, per dk $ 2.67 $ 3.02 $ 3.50 Williston Basin -- Natural Gas Transmission Operations Years ended December 31, 1996 1995 1994 Operating revenues: Transportation $ 60.4* $ 54.1* $ 52.6* Storage 10.7 12.6 10.6 Natural gas production and other 7.5 5.2 7.7 78.6 71.9 70.9 Operating expenses: Operation and maintenance 37.2* 35.7* 38.8* Depreciation, depletion and amortization 6.7 7.0 6.6 Taxes, other than income 4.5 3.8 4.2 48.4 46.5 49.6 Operating income 30.2 25.4 21.3 Volumes (dk): Transportation-- Montana-Dakota 43.4 35.4 33.0 Other 38.8 32.6 30.9 82.2 68.0 63.9 Produced (Mdk) 6,073 4,981 4,732 * Includes amortization and related recovery of deferred natural gas contract buy-out/ buy-down and gas supply realignment costs $ 10.6 $ 11.4 $ 12.8 Knife River -- Construction Materials and Mining Operations Years ended December 31, 1996** 1995** 1994 Operating revenues: Construction materials $ 99.5 $ 73.1 $ 71.0 Coal 32.7 39.9 45.6 132.2 113.0 116.6 Operating expenses: Operation and maintenance 105.8 87.8 88.2 Depreciation, depletion and amortization 7.0 6.2 6.4 Taxes, other than income 3.3 4.5 5.4 116.1 98.5 100.0 Operating income 16.1 14.5 16.6 Sales (000's): Aggregates (tons) 3,374 2,904 2,688 Asphalt (tons) 694 373 391 Ready-mixed concrete (cubic yards) 340 307 315 Coal (tons) 2,899 4,218 5,206 ** Does not include information related to Knife River's 50 percent ownership interest in Hawaiian Cement which was acquired in September 1995 and is accounted for under the equity method. Fidelity Oil -- Oil and Natural Gas Production Operations Years ended December 31, 1996 1995 1994 Operating revenues: Oil $ 39.0 $ 30.1 $ 20.9 Natural gas 29.3 18.7 17.1 68.3 48.8 38.0 Operating expenses: Operation and maintenance 15.6 13.7 12.0 Depreciation, depletion and amortization 25.0 18.6 13.5 Taxes, other than income 3.5 2.6 3.7 44.1 34.9 29.2 Operating income 24.2 13.9 8.8 Production (000's): Oil (barrels) 2,149 1,973 1,565 Natural gas (Mcf) 14,067 12,319 9,228 Average sales price: Oil (per barrel) $17.91 $ 15.07 $ 13.14 Natural gas (per Mcf) 2.09 1.51 1.84 Amounts presented in the above tables for natural gas operating revenues, purchased natural gas sold and operation and maintenance expenses will not agree with the Consolidated Statements of Income due to the elimination of intercompany transactions between Montana-Dakota's natural gas distribution business and Williston Basin's natural gas transmission business. The amounts relating to the elimination of intercompany transactions for natural gas operating revenues, purchased natural gas sold and operation and maintenance expenses were $58.2 million, $53.8 million and $4.4 million, respectively, for 1996, $54.6 million, $49.2 million and $5.4 million, respectively, for 1995, and $65.2 million, $58.5 million and $6.7 million, respectively, for 1994. 1996 compared to 1995 Montana-Dakota -- Electric Operations Operating income at the electric business decreased primarily due to increased fuel and purchased power costs, resulting primarily from both higher purchased power demand charges and increased net sales. The increase in demand charges, related to a participation power contract, is the result of the pass-through of periodic maintenance costs as well as the purchase of an additional five megawatts of capacity beginning in May 1996, which brings the total level of capacity available under this contract to 66 megawatts. Also contributing to the operating income decline were higher operation expenses, primarily resulting from higher transmission and payroll-related costs due to establishing certain contingency reserves, and higher depreciation expense, due to an increase in average depreciable plant. Increased revenues, primarily higher retail sales due to increased weather-related demand from residential and commercial customers in the first and fourth quarters, largely offset the operating income decline. Lower sales for resale volumes due to line capacity restrictions within the regional power pool were more than offset by higher average realized rates also partially offsetting the operating revenue increase. Earnings for the electric business decreased due to the operating income decline, and decreased service and repair income and lower investment income, both included in Other income -- net. Montana-Dakota -- Natural Gas Distribution Operations Operating income at the natural gas distribution business improved largely as a result of increased sales revenue. The sales revenue improvement resulted primarily from a 3.6 million decatherm increase in volumes sold due to 14% colder weather and increased sales resulting from the addition of over 3,600 customers. Also contributing to the sales revenue improvement were the effects of a general rate increase placed into effect in Montana in May 1996. However, the pass-through of lower average natural gas costs partially offset the sales revenue improvement. Decreased operations expense due to lower payroll-related costs also added to the operating income improvement. Lower transportation revenues, primarily decreased volumes transported to large industrial customers, somewhat offset the operating income improvement. Industrial transportation declined due to lower volumes transported to two agricultural processing facilities, one which closed in September 1995, and one which experienced lower production, and to a cement manufacturing facility due to its use of alternate fuel. Natural gas distribution earnings increased due to the operating income improvement, decreased interest expense and higher service and repair income. The decline in interest expense resulted from lower average long-term debt and natural gas costs refundable through rate adjustment balances. Williston Basin -- Natural Gas Transmission Operations Operating income at the natural gas transmission business increased primarily due to an improvement in transportation revenues resulting from increased transportation of natural gas held under the repurchase commitment, increased volumes transported to storage and the reversal of certain reserves for regulatory contingencies of $3.9 million ($2.4 million after tax). The benefits derived from a favorable rate change implemented in January 1996, also added to the revenue improvement. The nonrecurring effect of a favorable FERC order received in April 1995, on a rehearing request relating to a 1989 general rate proceeding partially offset the transportation revenue improvement. The order allowed for the one-time billing of customers for approximately $2.7 million ($1.7 million after tax) to recover a portion of the amount previously refunded in July 1994. In addition, reduced recovery of deferred natural gas contract buy- out/buy-down and gas supply realignment costs partially offset the increase in transportation revenue. An increase in natural gas production revenue, due to both higher volumes and prices, also contributed to the operating income improvement. Decreased storage revenues, due primarily to the implementation of lower rates in January 1996, partially offset the increase in operating income. Operation expenses increased primarily due to higher payroll- related costs and production royalties but were slightly offset by reduced amortization of deferred natural gas contract buy-out/buy- down costs. Earnings for this business decreased due to the write-down to the then current market price of the natural gas available under the repurchase commitment. The effect of the write-down, which was $21.1 million, or $12.9 million after tax, was significantly offset by the reversal of certain income tax reserves aggregating $4.8 million. Decreased interest income, largely related to $583,000 (after tax) of interest on the previously discussed 1995 refund recovery combined with higher company production refunds (both included in Other income -- net), also added to the earnings decline. Increased net interest expense ($366,000 after tax), largely resulting from higher average reserved revenue balances partially offset by decreased long-term debt expense due to lower average borrowings, further reduced earnings. The earnings decrease was somewhat offset by the increase in operating income. Knife River -- Construction Materials and Mining Operations Construction Materials Operations -- Construction materials operating income increased $3.3 million due to higher revenues. The revenue improvement is largely due to revenues realized as a result of the Baldwin and Medford acquisitions. Revenues at most other construction materials operations decreased as a result of lower aggregate and asphalt sales due to lower demand, and lower construction sales due to the nature of work being performed this year as compared to last year, offset in part by increased building materials sales and aggregate and ready-mixed concrete prices. Operation and maintenance expenses increased due to the above acquisitions but were somewhat offset by a reduction at other construction materials operations resulting from lower volumes sold and less work involving the use of subcontractors. Coal Operations -- Operating income for coal operations decreased $1.7 million primarily due to decreased revenues, largely the result of the expiration of the coal contract with the Big Stone Station in August 1995, and the resulting closure of the Gascoyne Mine. Higher average sales prices due to price increases at the Beulah Mine partially offset the decreased coal revenues. Decreased operation and maintenance expenses, depreciation expense and taxes other than income, largely due to the mine closure, partially offset the decline in operating income. Consolidated -- Earnings increased due to the increase in construction materials operating income and income from Hawaiian Cement of $1.7 million as compared to $1.0 million in 1995(included in Other income -- net). Higher interest expense ($1.4 million after tax), resulting mainly from increased long-term debt due to the acquisition of Hawaiian Cement, Baldwin and Medford, and the decline in coal operating income somewhat offset the increase in earnings. Fidelity Oil -- Oil and Natural Gas Production Operations Operating income for the oil and natural gas production business increased primarily as a result of higher oil and natural gas revenues. Higher oil revenue resulted from a $5.6 million increase due to higher average prices and a $3.2 million increase due to improved production. The increase in natural gas revenue was due to a $7.0 million increase arising from higher prices and a $3.6 million improvement resulting from higher production. Increased operation and maintenance expenses, largely due to higher production, and higher taxes other than income, primarily the result of higher prices, both partially offset the operating income improvement. Also reducing operating income was increased depreciation, depletion and amortization expense resulting from increased average rates and higher production. Depreciation, depletion and amortization rates increased in part due to the accrual of estimated future well abandonment costs ($515,000 after tax). Earnings for this business unit increased due to the operating income improvement and lower income taxes due to the reversal of certain tax reserves aggregating $1.8 million. Increased interest expense ($815,000 after tax), resulting mainly from higher average borrowings, and lower tax benefits somewhat offset the earnings improvement. 1995 compared to 1994 Montana-Dakota -- Electric Operations Operating income at the electric business increased primarily due to higher retail sales revenues and lower fuel and purchased power costs. Higher average usage by residential and commercial customers, due to more normal weather, contributed to the revenue improvement. Reduced demand by oil producers and refiners contributed to a decline in industrial sales, which somewhat offset the retail sales revenue improvement. Fuel and purchased power costs decreased due to changes in generation mix between lower and higher cost generating stations. This decrease was partially offset by higher purchased power demand charges. The increase in demand charges, related to a participation power contract, is the result of the purchase of an additional five megawatts of capacity beginning in May 1995, offset in part by the pass-through of periodic maintenance costs during 1994. Decreased maintenance expenses at the Coyote Station, due to less scheduled downtime, partially offset by increased turbine, generator and boiler maintenance at the Heskett Station, also improved operating income. Increased depreciation expense, due to higher average depreciable plant, and lower sales for resale due to a surplus of low-cost hydroelectric energy available from the Western Area Power Administration during August through November 1995 partially offset the increase in operating income. Earnings for the electric business improved due to the operating income increase, partially offset by higher income taxes. Montana-Dakota -- Natural Gas Distribution Operations Operating income increased at the natural gas distribution business due to the effect of $2.3 million in general rate increases and improved sales. The sales improvement resulted from the addition of over 5,100 customers and more normal weather than 1994. The pass-through of lower average natural gas costs and the effects of a Wyoming Supreme Court order granting recovery in 1994 of a prior refund made by Montana-Dakota reduced revenues. The effect of higher volumes transported were largely offset by lower average transportation rates. Higher operation expenses, due primarily to higher payroll-related costs somewhat offset by lower sales expenses, partially offset the operating income improvement. Increased depreciation expense, due to higher average depreciable plant, also partially offset the increase in operating income. Natural gas distribution earnings increased due to the improvement in operating income. A decreased return realized on net storage gas inventory and deferred demand costs partially offset the earnings increase. This return decline of approximately $619,000 (after tax) results from decreases in the net book balance on which the natural gas distribution business is allowed to earn a return. Williston Basin -- Natural Gas Transmission Operations Natural gas transmission operating income increased primarily due to an increase in transportation and storage revenues. The transportation revenue increase resulted primarily from the benefits of the favorable FERC order received in April 1995 on a rehearing request relating to a 1989 general rate proceeding as previously discussed. In addition, higher demand revenues associated with the storage enhancement project completed in late 1994, and increased volumes transported to storage, somewhat offset by decreased transportation of natural gas held under the repurchase commitment and reduced recovery of deferred natural gas contract buy-out/buy-down and gas supply realignment costs, added to the transportation revenue improvement. Lower operation and maintenance expenses, primarily lower production royalty expenses and reduced amortization of deferred natural gas contract buy- out/buy-down and gas supply realignment costs, and lower taxes other than income, largely lower production taxes, further contributed to the increase in operating income. A decline in natural gas production revenue, primarily due to a 54 cent per decatherm decline in realized natural gas prices, somewhat reduced by increased volumes produced, partially offset the increase in operating income. Increased depreciation expense, resulting from higher average depreciable plant, also somewhat reduced the operating income improvement. Earnings for this business improved due primarily to the increase in operating income, higher interest income, lower company production refunds (included in Other income -- net) and lower interest expense. Higher interest income of $583,000 (after tax) is related to the previously described refund recovery. The decline in interest expense aggregating $623,000 (after tax) is primarily due to long-term debt retirements and lower interest rates. Increased carrying costs on the natural gas repurchase commitment, due to higher average interest rates, partially offset the earnings increase. Knife River -- Construction Materials and Mining Operations Construction Materials Operations -- Construction materials operating income declined $636,000 primarily due to higher operation expenses. Operation expenses increased due primarily to additional work required to be subcontracted, due to unusually wet weather, and increased sales volumes. Increased revenues due to higher aggregate sales volumes, increased cement sales volumes at higher prices, increased soil remediation volumes, higher ready-mixed concrete prices, higher construction and aggregate delivery revenues and increased steel fabrication sales volumes, partially offset the operating income decline. Lower asphalt sales, due to increased competition, lower ready-mixed concrete sales and lower average soil remediation prices partially offset the revenue improvement. Coal Operations -- Operating income for the coal operations decreased $1.5 million primarily due to decreased coal revenues, primarily the result of lower sales to the Big Stone Station due to the expiration of the coal contract in August 1995 and the resulting closure of the Gascoyne Mine. Decreased operation expenses, resulting primarily from lower sales volumes and lower depreciation expense and lower taxes other than income, both due primarily to the closure of the Gascoyne Mine, partially offset the decline in operating income. Consolidated -- Earnings decreased due to the decline in coal and construction materials operating income and increased interest expense, due to increased long-term debt borrowings. Income from the 50 percent interest in Hawaiian Cement acquired in September 1995 and gains from the sale of equipment relating to the Gascoyne Mine closure, partially offset the decline in earnings. These items are reflected in Other income -- net. Fidelity Oil -- Oil and Natural Gas Production Operations Operating income for the oil and natural gas production business increased primarily as a result of higher oil revenues, $5.4 million of which was due to increased production, and $3.8 million of which stemmed from higher average oil prices. Also, increased natural gas revenue, $5.7 million of which was due to higher natural gas volumes produced partially offset by a $4.1 million revenue decrease resulting from lower natural gas prices, contributed to the operating income improvement. Also adding to operating income was decreased production taxes, stemming largely from the timing of payments in 1995 as compared to 1994. Operation expenses increased, as a result of higher production but were somewhat offset by lower average production costs, partially offsetting the operating income improvement. Also reducing operating income was increased depreciation, depletion and amortization expense largely due to higher production. Earnings for this business declined due to the 1994 realization of a $4.5 million gain (after tax) related to the sale of an equity investment in GARI. The increase in operating income partially offset the earnings decrease. Safe Harbor for Forward-Looking Statements The Company is including the following cautionary statement in this Form 10-K to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation management's examination of historical operating trends, data contained in the Company's records and other data available from third parties, but there can be no assurance that the Company's expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the Company's business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. Regulated Operations-- In addition to other factors and matters discussed elsewhere herein, some important factors that could cause actual results or outcomes for the Company and its regulated operations to differ materially from those discussed in forward-looking statements include prevailing governmental policies and regulatory actions with respect to allowed rates of return, financings, or industry and rate structures, weather conditions, acquisition and disposal of assets or facilities, operation and construction of plant facilities, recovery of purchased power and purchased gas costs, present or prospective generation, wholesale and retail competition (including but not limited to electric retail wheeling and transmission costs), availability of economic supplies of natural gas, and present or prospective natural gas distribution or transmission competition (including but not limited to prices of alternate fuels and system deliverability costs). Non-regulated Operations-- Certain important factors which could cause actual results or outcomes for the Company and all or certain of its non-regulated operations to differ materially from those discussed in forward- looking statements include the level of governmental expenditures on public projects and project schedules, changes in anticipated tourism levels, competition from other suppliers, oil and natural gas commodity prices, drilling successes in oil and natural gas operations, ability to acquire oil and natural gas properties, and the availability of economic expansion or development opportunities. Factors Common to Regulated and Non-Regulated Operations-- The business and profitability of the Company are also influenced by economic and geographic factors, including political and economic risks, changes in and compliance with environmental and safety laws and policies, weather conditions, population growth rates and demographic patterns, market demand for energy from plants or facilities, changes in tax rates or policies, unanticipated project delays or changes in project costs, unanticipated changes in operating expenses or capital expenditures, labor negotiations or disputes, changes in credit ratings or capital market conditions, inflation rates, inability of the various counterparties to meet their obligations with respect to the Company's financial instruments, changes in accounting principles and/or the application of such principles to the Company, changes in technology and legal proceedings. New Accounting Standard In October 1996, the American Institute of Certified Public Accountants issued Statement of Position 96-1, "Environmental Remediation Liabilities" (SOP 96-1). SOP 96-1 provides authoritative guidance for the recognition, measurement, display and disclosure of environmental remediation liabilities in financial statements. The Company will adopt SOP 96-1 on January 1, 1997, and the adoption is not expected to have a material effect on the Company's financial position or results of operations. Liquidity and Capital Commitments The Company's net capital expenditures (in millions of dollars) for 1994 through 1996 and as anticipated for 1997 through 1999 are summarized in the following table, which also includes the Company's capital needs for the retirement of maturing long-term securities. Actual Estimated 1994 1995 1996 Capital Expenditures-- 1997 1998 1999 Montana-Dakota: $ 14.2 $19.7 $18.7 Electric $17.0 $17.8 $20.1 13.2 8.9 6.3 Natural Gas Distribution 9.5 8.1 8.1 27.4 28.6 25.0 26.5 25.9 28.2 14.4 9.7 10.1 Williston Basin* 12.6 13.3 29.3 3.6 36.8 25.0 Knife River 35.4 13.9 11.1 38.6 39.9 51.8 Fidelity 55.0 55.0 60.0 1.0 2.6 .8 Prairielands * * * 85.0 117.6 112.7 129.5 108.1 128.6 Net proceeds from sale or (3.6) (2.8) (11.8) disposition of property (5.5) (4.4) (4.3) 81.4 114.8 100.9 Net capital expenditures 124.0 103.7 124.3 Retirement of Long-term Debt/Preferred Stock-- 28.3 10.4 35.4 Montana-Dakota 11.4 6.4 6.4 7.5 10.0 7.5 Williston Basin .5 .4 .5 --- --- --- Fidelity --- 7.7 8.3 --- .1 .5 Prairielands * * * 35.8 20.5 43.4 11.9 14.5 15.2 $117.2 $135.3 $144.3 Total $135.9 $118.2 $139.5 * Effective January 1, 1997, information related to Prairielands is included with Williston Basin. In reconciling net capital expenditures to investing activities per the Consolidated Statements of Cash Flows, the net capital expenditures for Prairielands, which is not considered a major business segment, are not reflected in investing activities in the Consolidated Statements of Cash Flows for 1994, 1995 and 1996. In addition, the 1994 capital expenditures for Montana-Dakota's natural gas distribution business are reflected net of $5.8 million of storage gas purchased from Williston Basin while the 1994 Williston Basin amount is reflected in the table above net of the sale of storage gas of $8.3 million. In 1996 Montana-Dakota provided all the funds needed for its net capital expenditures and securities retirements, excluding the $25 million discussed below, from internal sources. Montana-Dakota expects to provide all of the funds required for its net capital expenditures and securities retirements for the years 1997 through 1999 from internal sources, through the use of its $30 million revolving credit and term loan agreement, $30 million of which was outstanding at December 31, 1996, and through the issuance of long- term debt, the amount and timing of which will depend upon the Company's needs, internal cash generation and market conditions. In June 1996, the Company redeemed $25 million of its 9 1/8% Series first mortgage bonds, due May 15, 2006. The funds required to retire the 9 1/8% Series first mortgage bonds were provided by Williston Basin's repayment of $27.5 million of intercompany debt payable to the Company. Williston Basin's 1996 net capital expenditures and securities retirements were met through internally generated funds and the issuance of long-term debt as discussed below. Williston Basin expects to meet its net capital expenditures for the years 1997 through 1999 with a combination of internally generated funds, short-term lines of credit aggregating $40.4 million, $2 million of which was outstanding at December 31, 1996, and through the issuance of long-term debt, the amount and timing of which will depend upon Williston Basin's needs, internal cash generation and market conditions. In May 1996, Williston Basin privately placed $20 million of notes with the proceeds and cash on hand used to repay the $27.5 million of intercompany debt payable to the Company. In addition, in November 1996, Williston Basin privately placed $15 million of notes with the proceeds used to replace other maturing long-term debt. Knife River's 1996 net capital expenditures including the acquisitions of Baldwin and Medford, were met through funds on hand, funds generated from internal sources, short-term lines of credit and a revolving credit agreement. It is anticipated that funds generated from internal sources, short-term lines of credit aggregating $11 million, none of which was outstanding at December 31, 1996, a revolving credit agreement of $55 million, $47 million of which was outstanding at December 31, 1996, and the issuance of long-term debt and the Company's equity securities will meet the needs of this business unit for 1997 through 1999. In April 1996, amounts available under the revolving credit agreement were increased from $40 million to $55 million. Also in April 1996, amounts available under the short-term lines of credit were increased from $6 million to $8 million and in August 1996, were further increased from $8 to $11 million. Fidelity Oil's 1996 net capital expenditures related to its oil and natural gas acquisition, development and exploration program were met through funds generated from internal sources and long- term credit facilities. Fidelity's borrowing base, based on proven and producing reserves, is currently $65 million, which consists of $23 million of issued notes, $7 million in an uncommitted note shelf facility, and a $35 million revolving line of credit, $14.8 million of which was outstanding at December 31, 1996. In April 1996, the borrowing base was increased from $55 million to $65 million and concurrently the amount available under the revolving line of credit was increased from $25 million to $35 million. It is anticipated that Fidelity's 1997 through 1999 net capital expenditures and debt retirements will be met from internal sources and existing long-term credit facilities. The Company utilizes its short-term lines of credit aggregating $40 million, $2 million of which was outstanding on December 31, 1996, and its $30 million revolving credit and term loan agreement, all of which is outstanding at December 31, 1996, to meet its short-term financing needs and to take advantage of market conditions when timing the placement of long-term or permanent financing. The Company's issuance of first mortgage debt is subject to certain restrictions imposed under the terms and conditions of its Indenture of Mortgage. Generally, those restrictions require the Company to pledge $1.43 of unfunded property to the Trustee for each dollar of indebtedness incurred under the Indenture and that annual earnings (pretax and before interest charges), as defined in the Indenture, equal at least two times its annualized first mortgage bond interest costs. Under the more restrictive of the two tests, as of December 31, 1996, the Company could have issued approximately $247 million of additional first mortgage bonds. The Company's coverage of fixed charges including preferred dividends was 2.7 and 3.0 times for 1996 and 1995, respectively. Additionally, the Company's first mortgage bond interest coverage was 5.4 times in 1996 compared to 3.9 times in 1995. Common stockholders' investment as a percent of total capitalization was 54% and 57% at December 31, 1996 and 1995, respectively. Effects of Inflation The Company's consolidated financial statements reflect historical costs, thus combining the impact of dollars spent at various times. Such dollars have been affected by inflation, which generally erodes the purchasing power of monetary assets and increases operating costs. During times of chronic inflation, the loss of purchasing power and increased operating costs could potentially result in inadequate returns to stockholders primarily because of the lag in rate relief granted by regulatory agencies. Further, because the ratemaking process restricts the amount of depreciation expense to historical costs, cash flows from the recovery of such depreciation are inadequate to replace utility plant. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Reference is made to Pages 23 through 47 of the Annual Report. ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Reference is made to Pages 1 through 5 and 18 and 19 of the Company's Proxy Statement dated March 3, 1997 (Proxy Statement) which is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION Reference is made to Pages 13 through 18 of the Proxy Statement. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Reference is made to Page 19 of the Proxy Statement. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) Financial Statements, Financial Statement Schedules and Exhibits. Index to Financial Statements and Financial Statement Schedules. Page 1. Financial Statements: Report of Independent Public Accountants * Consolidated Statements of Income for each of the three years in the period ended December 31, 1996 * Consolidated Balance Sheets at December 31, 1996, 1995 and 1994 * Consolidated Statements of Capitalization at December 31, 1996, 1995 and 1994 * Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1996 * Notes to Consolidated Financial Statements * 2. Financial Statement Schedules (Schedules are omitted because of the absence of the conditions under which they are required, or because the information required is included in the Company's Consolidated Financial Statements and Notes thereto.) ____________________ * The Consolidated Financial Statements listed in the above index which are included in the Company's Annual Report to Stockholders for 1996 are hereby incorporated by reference. With the exception of the pages referred to in Items 6 and 8, the Company's Annual Report to Stockholders for 1996 is not to be deemed filed as part of this report. 3. Exhibits: 3(a) Composite Certificate of Incorporation of the Company, as amended to date, filed as Exhibit 3(a) to Form 10-K for the year ended December 31, 1994, in File No. 1-3480 * 3(b) By-laws of the Company, as amended to date ** 4(a) Indenture of Mortgage, dated as of May 1, 1939, as restated in the Forty-Fifth Supplemental Indenture, dated as of April 21, 1992, and the Forty-Sixth through Forty-Eighth Supplements thereto between the Company and the New York Trust Company (The Bank of New York, successor Corporate Trustee) and A. C. Downing (W. T. Cunningham, successor Co-Trustee), filed as Exhibit 4(a) in Registration No. 33-66682; and Exhibits 4(e), 4(f) and 4(g) in Registration No. 33-53896 * 4(b) Rights Agreement, dated as of November 3, 1988, between the Company and Norwest Bank Minnesota, N.A., Rights Agent, filed as Exhibit 4(c) in Registration No. 33-66682 * + 10(a) Executive Incentive Compensation Plan ** + 10(b) 1992 Key Employee Stock Option Plan, filed as Exhibit 10(f) in Registration No. 33-66682 * + 10(c) Restricted Stock Bonus Plan, filed as Exhibit 10(b) in Registration No. 33-66682 * + 10(d) Supplemental Income Security Plan, as amended to date ** + 10(e) Directors' Compensation Policy, filed as Exhibit 10(d) in Registration No. 33-66682 * + 10(f) Deferred Compensation Plan for Directors, filed as Exhibit 10(e) in Registration No. 33-66682 * + 10(g) Non-Employee Director Stock Compensation Plan, filed as Exhibit 10(g) to Form 10-K for the year ended December 31, 1995, in File No. 1-3480 * 12 Computation of Ratio of Earnings to Fixed Charges ** 13 Selected financial data, financial statements and supplementary data as contained in the Annual Report to Stockholders for 1996 ** 21 Subsidiaries of MDU Resources Group, Inc. ** 23(a) Consent of Independent Public Accountants ** 23(b) Consent of Engineer ** 23(c) Consent of Engineer ** 27 Financial Data Schedule ** ____________________ * Incorporated herein by reference as indicated. ** Filed herewith. + Management contract, compensatory plan or arrangement required to be filed as an exhibit to this form pursuant to Item 14(c) of this report. 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. MDU RESOURCES GROUP, INC. Date: February 28, 1997 By: /s/ Harold J. Mellen, Jr. Harold J. Mellen, Jr. (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 in the capacities and on the date indicated. Signature Title Date /s/ Harold J. Mellen, Jr. Chief Executive February 28, 1997 Harold J. Mellen, Jr. Officer (President and Chief Executive Officer) and Director /s/ Douglas C. Kane Chief Operating February 28, 1997 Douglas C. Kane (Executive Vice President Officer and and Chief Operating Officer) Director /s/ Warren L. Robinson Chief Financial February 28, 1997 Warren L. Robinson (Vice President, Officer Treasurer and Chief Financial Officer) /s/ Vernon A. Raile Chief Accounting February 28, 1997 Vernon A. Raile (Vice President, Officer Controller and Chief Accounting Officer) /s/ John A. Schuchart Director February 28, 1997 John A. Schuchart (Chairman of the Board) /s/ San W. Orr, Jr. Director February 28, 1997 San W. Orr, Jr. (Vice Chairman of the Board) /s/ Thomas Everist Director February 28, 1997 Thomas Everist /s/ Richard L. Muus Director February 28, 1997 Richard L. Muus /s/ Robert L. Nance Director February 28, 1997 Robert L. Nance /s/ John L. Olson Director February 28, 1997 John L. Olson /s/ Homer A. Scott, Jr. Director February 28, 1997 Homer A. Scott, Jr. /s/ Joseph T. Simmons Director February 28, 1997 Joseph T. Simmons /s/ Sister Thomas Welder Director February 28, 1997 Sister Thomas Welder EX-3.B 2 BY-LAWS TABLE OF CONTENTS TO BYLAWS Amendments Certificates of Stock Chairman and Vice Chairman of the Board Checks Chief Executive Officer Chief Operating Officer Committees Compensation of Directors Directors Directors and Officers Indemnified Directors Meetings Dividends Election of Officers Execution of Instruments Execution of Proxies Fiscal Year Inspection of Books and Records Lost Certificates Notices Officers Offices President Qualifications Record Date Registered Stockholders Seal Secretary and Assistant Secretaries Stockholders Meetings Transfers of Stock Treasurer and Assistant Treasurer Vice Presidents BYLAWS OF MDU RESOURCES GROUP, INC. OFFICES 1.01 Registered Office. The registered office shall be in the City of Wilmington, County of New Castle, State of Delaware. 1.02 Other Offices. The Corporation may also have offices at such other places, both within and without the State of Delaware, as the Board of Directors may from time to time determine or the business of the Corporation may require. MEETINGS OF STOCKHOLDERS 2.01 Place of Meetings. All meetings of the stockholders for the election of Directors shall be held in the City of Bismarck, State of North Dakota, at such place as may be fixed from time to time by the Board of Directors, or at such other place, either within or without the State of Delaware, as shall be designated from time to time by the Board of Directors and stated in the notice of the meeting. Meetings of stockholders for any other purpose may be held at such time and place, within or without the State of Delaware, as shall be stated in the notice of the meeting or in a duly executed waiver of notice thereof. 2.02 Annual Meetings. Annual meetings of stockholders, commencing with the year 1973, shall be held on the fourth Tuesday of April in each year, if not a legal holiday, and if a legal holiday, then on the next secular day following, at 11:00 A.M., or at such other date and time as shall be designated from time to time by the Board of Directors and stated in the notice of the meeting, at which they shall elect by a plurality vote, by written ballot, a Board of Directors, and transact such other business as may properly be brought before the meeting. 2.03 Notice of Annual Meeting. Written notice of the annual meeting, stating the place, date and hour of the meeting, shall be given to each stockholder entitled to vote at such meeting not less than ten nor more than sixty days before the date of the meeting. 2.04 Stockholders List. The officer who has charge of the stock ledger of the Corporation shall prepare and make, at least ten days before every meeting of stockholders, a complete list of the stockholders entitled to vote at the meeting, arranged in alphabetical order, and showing the address of each stockholder and the number of shares registered in the name of each stockholder. Such list shall be open to the examination of any stockholder, for any purpose germane to the meeting, during ordinary business hours, for a period of at least ten days prior to the meeting, either at a place within the City where the meeting is to be held, which place shall be specified in the notice of the meeting, or, if not so specified, at the place where the meeting is to be held. The list shall also be produced and kept at the time and place of the meeting during the whole time thereof, and may be inspected by any stockholder who is present. 2.05 Notice of Special Meeting. Written notice of a special meeting, stating the place, date and hour of the meeting and the purpose or purposes for which the meeting is called, shall be given not less than ten nor more than sixty days before the date of the meeting, to each stockholder entitled to vote at such meeting. 2.06 Quorum. The holders of a majority of the stock issued and outstanding and entitled to vote in person or by proxy, shall constitute a quorum at all meetings of the stockholders for the transaction of business, except as provided herein and except as otherwise provided by statute or by the Certificate of Incorporation. If, however, such quorum shall not be present or represented at any meeting of the stockholders, the stockholders entitled to vote thereat, present in person or represented by proxy, shall have power to adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present or represented. At such adjourned meeting at which a quorum shall be present or represented, any business may be transacted which might have been transacted at the meeting as originally notified. If the adjournment is for more than thirty days, or if, after the adjournment, a new record date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given to each stockholder of record entitled to vote at the meeting. 2.07 Voting Rights. When a quorum is present at any meeting, the vote of the holders of a majority of the stock having voting power, present in person or represented by proxy, shall decide any question brought before such meeting, unless the question is one upon which, by express provision of the statutes, the Certificate of Incorporation or these Bylaws, a different vote is required, in which case such express provision shall govern and control the decision of such question. Unless otherwise provided in the Certificate of Incorporation, each stockholder shall, at every meeting of the stockholders, be entitled to one vote in person or by proxy for each share of the capital stock having voting power held by such stockholder, but no proxy shall be voted on after three years from its date, unless the proxy provides for a longer period. 2.08 Notice of Stockholder Nominees. Only persons who are nominated in accordance with the procedures set forth in this Section 2.08 shall be eligible for election as Directors. Nominations of persons for election to the Board of Directors of the Corporation may be made at the annual meeting of stockholders by or at the direction of the Board of Directors, or by any stockholder of the Corporation entitled to vote for the election of Directors at the meeting who complies with the notice procedures set forth in this Section 2.08. Such nominations, other than those made by or at the direction of the Board of Directors, shall be made pursuant to timely notice in writing to the Secretary of the Corporation. To be timely, a stockholder's notice shall be delivered or mailed and received at the principal executive offices of the Corporation not less than 90 days prior to the annual meeting; provided, however, that in the event that less than 100 days' notice or prior public disclosure of the date of the meeting is given or made to stockholders by the Corporation, notice by the stockholder to be timely must be so received not later than the close of business on the 10th day following the day on which such notice of the date of the meeting was mailed or such public disclosure was made by the Corporation. The stockholder's notice shall set forth (a) as to each person whom the stockholder proposes to nominate for election or re-election as a Director, (i) the name, age, business address and residence address of such person, (ii) the principal occupation or employment of such person, (iii) the class and number of shares of the Corporation which are beneficially owned by such person, and (iv) any other information relating to such person that is required to be disclosed in solicitations of proxies for election of Directors, or is otherwise required, in each case pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (including without limitation such person's written consent to being named in the proxy statement as a nominee and to serving as a Director if elected); and (b) as to the stockholder giving the notice, (i) the name and address, as they appear on the Corporation's books, of such stockholder, and (ii) the class and number of shares of the Corporation which are beneficially owned by such stockholder. At the request of the Board of Directors, any person nominated by the Board of Directors for election as a Director shall furnish to the Secretary of the Corporation that information required to be set forth in a stockholder's notice of nomination which pertains to the nominee. No person shall be eligible for election as a Director of the Corporation unless nominated in accordance with the procedures set forth in this Section 2.08. The Chairman of the meeting shall, if the facts warrant, determine and declare to the meeting that a nomination was not made in accordance with the procedures prescribed by the Bylaws, and if the Chairman should so determine, the Chairman shall so declare to the meeting and the defective nomination shall be disregarded. 2.09 Notice of Stockholder Business. At an annual meeting of the stockholders, only such business shall be conducted as shall have been properly brought before the meeting. To be properly brought before an annual meeting, business must be (a) specified in the notice of meeting (or any supplement thereto) given by or at the direction of the Board of Directors, (b) otherwise properly brought before the meeting or by the direction of the Board of Directors, or (c) otherwise properly brought before the meeting by a stockholder. For business to be properly brought before an annual meeting by a stockholder, the stockholder must have given timely notice thereof in writing to the Secretary of the Corporation. To be timely, the stockholder's notice must be delivered to or mailed and received at the principal executive offices of the Corporation, not less than 90 days prior to the meeting; provided, however, that in the event that less than 100 days' notice or prior public disclosure of the date of the meeting is given or made to stockholders by the Corporation, notice by the stockholder to be timely must be so received not later than the close of business on the 10th day following the day on which such notice of the date of the annual meeting was mailed or such public disclosure was made by the Corporation. The stockholder's notice to the Secretary shall set forth as to each matter the stockholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought to the annual meeting and the reasons for conducting business at the annual meeting, (b) the name and address, as they appear on the Corporation's books, of the stockholder proposing such business, (c) the class and number of shares of the Corporation which are beneficially owned by the stockholder, and (d) any material interest of the stockholder in such business. Notwithstanding anything in the Bylaws to the contrary, no business shall be conducted at any annual meeting except in accordance with the procedures set forth in this Section 2.09. The Chairman of the annual meeting shall, if the facts warrant, determine and declare to the meeting that business was not properly brought before the meeting and, in accordance with the provisions of this Section 2.09, and if he should so determine, the Chairman shall so declare to the meeting and such business not properly brought before the meeting shall not be transacted. DIRECTORS 3.01 Authority of Directors. The business of the Corporation shall be managed by its Board of Directors which may exercise all such powers of the Corporation and do all such lawful acts and things as are not by statute or by the Certificate of Incorporation or by these Bylaws directed or required to be exercised or done by the stockholders. 3.02 Qualifications. No person shall be eligible as a Director of the Corporation who at the time of his election has passed his seventieth birthday, provided that this age qualification shall not apply to those persons who are officers of the Corporation. Except for those persons who have served as Chief Executive Officer of the Corporation, a person shall be ineligible as a Director if at the time of his election he is a retired officer of the Corporation. A person who has served as Chief Executive Officer of the Corporation shall be ineligible as a Director if at the time of his election he has been retired as Chief Executive Officer for more than five years. The Board of Directors may elect from those persons who have been members of the Board of Directors, Directors Emeritus. 3.03 Place of Meetings. The Board of Directors of the Corporation may hold meetings, both regular and special, either within or without the State of Delaware. 3.04 Annual Meetings. The first meeting of each newly elected Board of Directors shall be held at such time and place as shall be specified in a notice given as herein provided for regular meetings of the Board of Directors, or as shall be specified in a duly executed waiver of notice thereof. 3.05 Regular Meetings. Regular meetings of the Board of Directors may be held at the office of the Corporation in Bismarck, North Dakota, on the second Thursday following the first Monday of February, May, August and November of each year; provided, however, that if a legal holiday, then on the next preceding day that is not a legal holiday. Regular meetings of the Board of Directors may be held at other times and other places within or without the State of North Dakota on at least five days' notice to each Director, either personally or by mail, telephone or telegram. 3.06 Special Meetings. Special meetings of the Board may be called by the Chairman of the Board, Chief Executive Officer or President on three days' notice to each Director, either personally or by mail, telephone or telegram; special meetings shall be called by the Chairman, Chief Executive Officer, President or Secretary in like manner and on like notice on the written request of a majority of the Board of Directors. 3.07 Quorum. At all meetings of the Board, a majority of the Directors shall constitute a quorum for the transaction of business and the act of a majority of the Directors present at any such meeting at which there is a quorum shall be the act of the Board of Directors, except as may be otherwise specifically provided by statute, the Certificate of Incorporation or by these Bylaws. If a quorum shall not be present at any meeting of the Board of Directors, the Directors present may adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present. 3.08 Participation of Directors by Conference Telephone. Unless otherwise restricted by the Certificate of Incorporation or these Bylaws, any member of the Board, or of any committee designated by the Board, may participate in any meeting of such Board or committee by means of conference telephone or similar communication equipment by means of which all persons participating in the meeting can hear each other. Participation in any meeting by means of conference telephone or similar communications equipment shall constitute presence in person at such meeting. 3.09 Written Action of Directors. Unless otherwise restricted by the Certificate of Incorporation or these Bylaws, any action required or permitted to be taken at any meeting of the Board of Directors or of any committee thereof may be taken without a meeting, if all members of the Board or committee, as the case may be, consent thereto in writing, and the writing or writings are filed with the minutes of proceedings of the Board or committee. 3.10 Committees. The Board of Directors may by resolution passed by a majority of the whole Board designate one or more committees, each committee to consist of two or more Directors of the Corporation. The Board may designate one or more Directors as alternate members of any committee who may replace any absent or disqualified member at any meeting of the committee. In the absence or disqualification of a member of a committee, the member or members thereof present at any meeting and not disqualified from voting, whether or not he or they constitute a quorum, may unanimously appoint another member of the Board of Directors to act at the meeting in the place of any such absent or disqualified member. The Chairman of the Board shall appoint another member of the Board of Directors to fill any committee vacancy which may occur. Any such committee shall have, and may exercise, the power and authority specifically granted by the Board to the committee, but no such committee shall have the power or authority to amend the Certificate of Incorporation, adopt an agreement of merger or consolidation, recommend to the stockholders the sale, lease or exchange of the Corporation's property and assets, recommend to the stockholders a dissolution of the Corporation or a revocation of a dissolution, or amend the Bylaws of the Corporation. Such committee or committees shall have such name or names as may be determined from time to time by resolution adopted by the Board of Directors. 3.11 Reports of Committees. Each committee shall keep regular minutes of its meetings and report the same to the Board of Directors when required. 3.12 Compensation of Directors. Unless otherwise restricted by the Certificate of Incorporation, the Board of Directors shall have the authority to fix the compensation of Directors. The Directors may be paid their expenses, if any, of attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors or a stated salary as Director. No such payment shall preclude any Director from serving the Corporation in any other capacity and receiving compensation therefor. Members of special or standing committees may be allowed compensation for attending committee meetings. 3.13 Chairman and Vice Chairman of the Board. The Chairman of the Board of Directors shall be chosen by the Board of Directors at its first meeting after the annual meeting of the stockholders of the Corporation. The Chairman shall preside at all meetings of the Board of Directors and stockholders of the Corporation, and shall, subject to the direction and control of the Board, be its representative and medium of communication, and shall perform such duties as may from time to time be assigned to the Chairman by the Board. The Vice Chairman shall be a Director and shall preside at all meetings of the stockholders and the Board of Directors in the absence of the Chairman of the Board. NOTICES 4.01 Notices. Whenever, under the provisions of the statutes or of the Certificate of Incorporation or of these Bylaws, notice is required to be given to any Director or stockholder, it shall not be construed to mean personal notice, but such notice may be given in writing, by mail, addressed to such Director or stockholder, at his address as it appears on the records of the Corporation, with postage thereon prepaid, and such notice shall be deemed to be given at the time when the same shall be deposited in the United States mail. Notice to Directors may also be given by telegram or telephone. 4.02 Waiver. Whenever any notice is required to be given under the provisions of the statutes or of the Certificate of Incorporation or of these Bylaws, a waiver thereof in writing, signed by the person or persons entitled to said notice, whether before or after the time stated therein, shall be deemed equivalent thereto. OFFICERS 5.01 Election, Qualifications. The officers of the Corporation shall be chosen by the Board of Directors at its first meeting after each annual meeting of stockholders and shall include a President, a Chief Executive Officer, a Chief Operating Officer, a Vice President, a Secretary and a Treasurer. The Board of Directors may also choose additional Vice Presidents, and one or more Assistant Vice Presidents, Assistant Secretaries and Assistant Treasurers. Any number of offices may be held by the same person, unless the Certificate of Incorporation or these Bylaws otherwise provide. 5.02 Additional Officers. The Board of Directors may appoint such other officers and agents as it shall deem necessary, who shall hold their offices for such terms and shall exercise such powers and perform such duties as shall be determined from time to time by the Board. 5.03 Salaries. The salaries of all principal officers of the Corporation shall be fixed by the Board of Directors. 5.04 Term. The officers of the Corporation shall hold office until their successors are chosen and qualify. Any officer elected or appointed by the Board of Directors may be removed at any time by the affirmative vote of a majority of the Board of Directors. Any vacancy occurring in any office of the Corporation shall be filled by the Board of Directors. 5.05 Chief Executive Officer. The Chief Executive Officer shall, subject to the authority of the Board of Directors, determine the general policies of the Corporation. The Chief Executive Officer shall submit a report of the operations of the Company for the fiscal year to the stockholders at their annual meeting and from time to time shall report to the Board of Directors all matters within his knowledge which the interests of the Corporation may require be brought to the Board's notice. 5.06 The President. The President shall have general and active management of the business of the Corporation and shall see that all orders and resolutions of the Board of Directors are carried into effect. 5.07 The Chief Operating Officer. The Chief Operating Officer shall have general management oversight of the subsidiaries and divisions of the Corporation. 5.08 The Vice Presidents. In the absence of the President or in the event of his inability or refusal to act, the Vice President (or in the event there be more than one Vice President, the Vice Presidents in the order designated, or in the absence of any designation, then in the order of their election) shall perform the duties of the President, and when so acting, shall have all the powers of and be subject to all the restrictions upon the President. The Vice Presidents shall perform such other duties and have such other powers as the Board of Directors may from time to time prescribe. 5.09 The Secretary and Assistant Secretaries. The Secretary shall record all the proceedings of the meetings of the stockholders and Directors in a book to be kept for that purpose. He shall give, or cause to be given, notice of all meetings of the stockholders and special meetings of the Board of Directors, and shall perform such other duties as may be prescribed by the Board of Directors or Chief Executive Officer, under whose supervision he shall be. He shall have custody of the corporate seal of the Corporation and he, or an assistant secretary, shall have authority to affix the same to any instrument requiring it. The Board of Directors may give general authority to any other officer to affix the seal of the Corporation. The Assistant Secretary, or if there be more than one, the Assistant Secretaries in the order determined by the Board of Directors (or if there be no such determination, then in the order of their election) shall, in the absence of the Secretary or in the event of his inability or refusal to act, perform the duties and exercise the powers of the Secretary and shall perform such other duties and have such other powers as the Board of Directors may from time to time prescribe. 5.10 Treasurer and Assistant Treasurers. The Treasurer shall have the custody of the corporate funds and securities and shall keep full and accurate accounts of receipts and disbursements in books belonging to the Corporation and shall deposit all moneys and other valuable effects in the name and to the credit of the Corporation in such depositories as may be designated by the Board of Directors. He shall disburse the funds of the Corporation as may be ordered by the Board of Directors, taking proper vouchers for such disbursements, and shall render to the President and the Board of Directors, at its regular meetings, or when the Board of Directors so requires, an account of all his transactions as Treasurer and of the financial condition of the Corporation. If required by the Board of Directors, he shall give the Corporation a bond (which shall be renewed every six years) in such sum and with such surety or sureties as shall be satisfactory to the Board of Directors for the faithful performance of the duties of his office and for the restoration to the Corporation, in case of his death, resignation, retirement or removal from office, of all books, papers, vouchers, money and other property of whatever kind in his possession or under his control belonging to the Corporation. The Assistant Treasurer, or if there shall be more than one, the Assistant Treasurers in the order determined by the Board of Directors (or if there be no such determination, then in the order of their election), shall, in the absence of the Treasurer or in the event of his inability or refusal to act, perform the duties and exercise the powers of the Treasurer and shall perform such other duties and have such other powers as the Board of Directors may from time to time prescribe. 5.11 Authority and Duties. In addition to the foregoing authority and duties, all officers of the Corporation shall respectively have such authority and perform such duties in the management of the business of the Corporation as may be designated from time to time by the Board of Directors. 5.12 Execution of Instruments. All deeds, bonds, mortgages, notes, contracts and other instruments requiring the seal of the Corporation shall be executed on behalf of the Corporation by the Chief Executive Officer, President, Chief Operating Officer or a Vice President and attested by the Secretary or an Assistant Secretary or by the Treasurer or an Assistant Treasurer, except where the execution and attestation thereof shall be expressly delegated by the Board of Directors to some other officer or agent of the Corporation. When authorized by the Board of Directors, the signature of any officer or agent of the Corporation may be a facsimile. 5.13 Execution of Proxies. All capital stocks in other corporations owned by this Corporation shall be voted at the meetings, regular and/or special, of stockholders of said other corporations by the Chief Executive Officer, President, or Chief Operating Officer of this Corporation, or, in the absence of any of them, by a Vice President, and in the event of the presence of more than one Vice President of this Corporation, then by a majority of said Vice Presidents present at such stockholders meetings, and the Chief Executive Officer, President, or Chief Operating Officer and Secretary of this Corporation are hereby authorized to execute in the name and under the seal of this Corporation proxies in such form as may be required by the corporations whose stock may be owned by this Corporation, naming as the attorney authorized to act in said proxy such individual or individuals as to said Chief Executive Officer, President, or Chief Operating Officer and Secretary shall deem advisable, and the attorney or attorneys so named in said proxy shall, until the revocation or expiration thereof, vote said stock at such stockholders meetings only in the event that none of the officers of this Corporation authorized to executive said proxy shall be present thereat. CERTIFICATES OF STOCK 6.01 Certificates. Every holder of stock in the Corporation shall be entitled to have a certificate signed by, or signed in the name of the Corporation by, the Chairman or Vice Chairman of the Board of Directors, or the Chief Executive Officer, President, Chief Operating Officer or a Vice President and by the Treasurer or an Assistant Treasurer, or the Secretary or an Assistant Secretary of the Corporation, certifying the number of shares owned by him in the Corporation. 6.02 Signatures. Any of or all the signatures on the certificates may be facsimile. In case any officer, transfer agent or registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, transfer agent or registrar before such certificate is issued, it may be issued by the Corporation with the same effect as if he were such officer, transfer agent or registrar at the date of issue. 6.03 Special Designation on Certificates. If the Corporation shall be authorized to issue more than one class of stock or more than one series of any class, the powers, designations, preferences and relative, participating, optional or other special rights of each class of stock or series thereof and the qualifications, limitations, or restrictions of such preferences and/or rights shall be set forth in full or summarized on the face or back of the certificate which the Corporation shall issue to represent such class or series of stock, provided, that, except as otherwise provided in Section 202 of the General Corporation Law of Delaware in lieu of the foregoing requirements, there may be set forth on the face or back of the certificate which the Corporation shall issue to represent such class or series of stock, a statement that the Corporation will furnish, without charge to each stockholder who so requests, the powers, designations, preferences and relative, participating, optional or other special rights of each class of stock or series thereof and the qualifications, limitations or restrictions of such preferences and/or rights. 6.04 Lost Certificates. The Board of Directors may direct a new certificate or certificates to be issued in place of any certificate or certificates theretofore issued by the Corporation alleged to have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the person claiming the certificate of stock to be lost, stolen or destroyed. When authorizing such issue of a new certificate or certificates, the Board of Directors may, in its discretion and as a condition precedent to the issuance thereof, require the owner of such lost, stolen or destroyed certificate or certificates, or his legal representative, to advertise the same in such manner as it shall require and/or to give the Corporation a bond in such sum as it may direct as indemnity against any claim that may be made against the Corporation with respect to the certificate alleged to have been lost, stolen or destroyed. 6.05 Transfers of Stock. Upon surrender to the Corporation or the transfer agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignation or authority to transfer, it shall be the duty of the Corporation to issue a new certificate to the person entitled thereto, cancel the old certificate and record the transaction upon its books. 6.06 Record Date. In order that the Corporation may determine the stockholders entitled to notice of or to vote at any meeting of stockholders or any adjournment thereof, or to express consent to corporate action in writing without a meeting, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action, the Board of Directors may fix, in advance, a record date, which shall not be more than sixty days nor less than ten days before the date of such meeting, nor more than sixty days prior to any other action. A determination of stockholders of record entitled to notice of or to vote at a meeting of stockholders shall apply to any adjournment of the meeting; provided, however, that the Board of Directors may fix a new record date for the adjourned meeting. 6.07 Registered Stockholders. The Corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends, and to vote as such owner, and to hold liable for calls and assessments a person registered on its books as the owner of shares, and shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of Delaware. GENERAL PROVISIONS 7.01 Dividends. Dividends upon the capital stock of the Corporation, subject to the provisions of the Certificates of Incorporation, if any, may be declared by the Board of Directors at any regular or special meeting, pursuant to law. Dividends may be paid in cash, in property, or in shares of the capital stock, subject to the provisions of the Certificates of Incorporation. Before payment of any dividend, there may be set aside out of the funds of the Corporation available for dividends such sum or sums as the Directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meeting contingencies, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for such other purpose as the Directors shall think conducive to the interest of the Corporation, and the Directors may modify or abolish any such reserve in the manner in which it was created. 7.02 Checks. All checks or demands for money and notes of the Corporation shall be signed by such officer or officers or such other person or persons as the Board of Directors may from time to time designate or as designated by an officer of the company if so authorized by the Board of Directors. 7.03 Fiscal year. The fiscal year of the Corporation shall be the calendar year. 7.04 Seal. The corporate seal shall have inscribed thereon the name of the Corporation, the year of its organization and the words "Corporate Seal, Delaware." The seal may be used by causing it or a facsimile thereof to be impressed or affixed or imprinted, or otherwise. 7.05 Inspection of Books and Records. Any stockholder of record, in person or by attorney or other agent, shall, upon written demand under oath stating the purpose thereof, have the right, during the usual hours of business, to inspect for any proper purpose the Corporation's stock ledger, a list of its stockholders, and its other books and records, and to make copies or extracts therefrom. A proper purpose shall mean a purpose reasonably related to such person's interest as a stockholder. In every instance where an attorney or other agent shall be the person who seeks the right to inspection, the demand under oath shall be accompanied by a power of attorney or such other writing which authorizes the attorney or other agent to so act on behalf of the stockholder. The demand under oath shall be directed to the Corporation at its registered office in the State of Delaware or at its principal place of business in Bismarck, North Dakota. 7.06 Amendments. These Bylaws may be altered, amended or repealed or new Bylaws may be adopted by the stockholders or by the Board of Directors, when such power is conferred upon the Board of Directors by the Certificate of Incorporation, at any regular meeting of the stockholders or of the Board of Directors or at any special meeting of the stockholders or of the Board of Directors if notice of such alteration, amendment, repeal or adoption of new Bylaws be contained in the notice of such special meeting. 7.07 Indemnification of Officers, Directors, Employees and Agents; Insurance. (a) The Corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the Corporation) by reason of the fact that he is or was a director, officer, employee or agent of the Corporation, or is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the Corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction, or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the person did not act in good faith and in a manner which he reasonably believed to be in or not opposed to the best interest of the Corporation, and, with respect to any criminal action or proceeding, had reasonable cause to believe that his conduct was unlawful. (b) The Corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the Corporation to procure a judgment in its favor by reason of the fact that he is or was a director, officer, employee or agent of the Corporation, or is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against expenses (including attorneys' fees) actually and reasonably incurred by him in connection with the defense or settlement of such action or suit if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the Corporation and except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the Corporation, unless and only to the extent that the Court of Chancery or the court in which such action or suit was brought, shall determine upon application that, despite the adjudication of liability but in view ofall the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Court of Chancery or such other court shall deem proper. (c) To the extent that a director, officer, employee or agent of a corporation has been successful on the merits or otherwise in defense of any action, suit or proceeding referred to in subsections (a) and (b), or in defense of any claim, issue or matter therein, he shall be indemnified against expenses (including attorneys' fees) actually and reasonably incurred by him in connection therewith. (d) Any indemnification under the foregoing provisions of this Section (unless ordered by a court) shall be made by the Corporation only as authorized in the specific case upon a determination that indemnification of the director, officer, employee or agent is proper in the circumstances because he has met the applicable standard of conduct as set forth in subsections (a) and (b) of this Section. Such determination shall be made (i) by a majority vote of the directors who are not parties to such action, suit or proceeding, even though less than a quorum, or (ii) if there are no such directors, or if such directors so direct, by independent legal counsel in a written opinion, or (iii) by the stockholders. (e) Expenses (including attorneys' fees) incurred by an officer or director in defending any civil, criminal, administrative or investigative action, suit or proceeding shall be paid by the Corporation in advance of the final disposition of such action, suit or proceeding upon receipt of an undertaking by or on behalf of the director or officer to repay such amount if it shall ultimately be determined that he is not entitled to be indemnified by the Corporation as authorized in this Section. Once the Corporation has received the undertaking, the Corporation shall pay the officer or director within 30 days of receipt by the Corporation of a written application from the officer or director for the expenses incurred by that officer or director. In the event the Corporation fails to pay within the 30-day period, the applicant shall have the right to sue for recovery of the expenses contained in the written application and, in addition, shall recover all attorneys' fees and expenses incurred in the action to enforce the application and the rights granted in this Section 7.07. Expenses (including attorneys' fees) incurred by other employees and agents shall be paid upon such terms and conditions, if any, as the Board of Directors deems appropriate. (f) The indemnification and advancement of expenses provided by, or granted pursuant to, the other subsections of this Section shall not be deemed exclusive of any other rights to which those seeking indemnity or advancement of expenses may be entitled under any bylaw, agreement, vote of stockholders or disinterested directors or otherwise, both as to action in his official capacity and as to action in another capacity while holding such office. (g) The Corporation may purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the Corporation, or is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against any liability asserted against him and incurred by him in any such capacity, or arising out of his status as such, whether or not the Corporation would have the power to indemnify him against such liability under the provisions of this Section. (h) For the purposes of this Section, references to "the Corporation" include all constituent corporations absorbed in a consolidation or merger, as well as the resulting or surviving corporation, so that any person who is or was a director, officer, employee or agent of such a constituent corporation or is or was serving at the request of such constituent corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, shall stand in the same position under the provisions of this Section with respect to the resulting or surviving corporation as he would if he had served the resulting or surviving corporation in the same capacity. (i) For purposes of this Section, references to "other enterprises" shall include employee benefit plans; references to "fines" shall include any excise taxes assessed on a person with respect to any employee benefit plan; and references to "serving at the request of the Corporation" shall include any service as a director, officer, employee or agent of the Corporation which imposes duties on, or involves services by, such director, officer, employee or agent with respect to an employee benefit plan, its participants or beneficiaries; and a person who acted in good faith and in a manner he reasonably believed to be in the interest of the participants and beneficiaries of an employee benefit plan shall be deemed to have acted in a manner "not opposed to the best interests of the Corporation" as referred to in this Section. (j) The indemnification and advancement of expenses provided by, or granted pursuant to, this Section shall, unless otherwise provided when authorized or ratified, continue as to a person who has ceased to be a director, officer, employee or agent and shall inure to the benefit of the heirs, executors and administrators of such a person. EX-10.A 3 EXECUTIVE INCENTIVE COMPENSATION PLAN MDU RESOURCES GROUP, INC. EXECUTIVE INCENTIVE COMPENSATION PLAN ____________________________________________________________ I. PURPOSE The purpose of the Executive Incentive Compensation Plan (the "Plan") is to provide an incentive for key executives of MDU Resources Group, Inc. (the "Company") to focus their efforts on the achievement of challenging and demanding corporate objectives. The Plan is designed to reward successful corporate performance as measured against specified performance goals as well as exceptional individual performance. When corporate performance reaches or exceeds the performance targets and individual performance is exemplary, incentive compensation awards, in conjunction with salaries, will provide a level of compensation which recognizes the skills and efforts of the key executives. II. BASIC PLAN CONCEPT The Plan provides an opportunity to earn annual incentive compensation based on the achievement of specified annual performance objectives. A target incentive award for each individual within the Plan is established based on the position level and assigned salary grade market value (midpoint). The target incentive award represents the amount to be paid, subject to the achievement of the performance objective targets established each year. Larger incentive awards than target may be authorized when performance exceeds targets, lesser or no amounts may be paid when performance is below target. It is recognized that during a Plan year major unforeseen changes in economic and environmental conditions or other significant factors beyond the control of management may substantially affect the ability of the Plan participants to achieve the specified performance goals. Therefore, in its review of corporate performance the Compensation Committee of the Board of Directors (the "Committee"), in consultation with the Chief Executive Officer of MDU Resources Group, Inc., may modify the performance targets. However, it is contemplated that such target modifications will be necessary only in years of unusually adverse or favorable external conditions. III. ADMINISTRATION The Plan shall be administered by the Committee with the assistance of the Chief Executive Officer of the MDU Resources Group, Inc. The Committee shall approve annually, prior to the beginning of each Plan year, the list of eligible participants, the Plan's performance targets, and the target incentive award level for each position within the Plan. The Committee shall have final discretion to determine actual award payment levels, method of payment, and whether or not payments shall be made for any Plan year. IV. ELIGIBILITY Executives who are determined by the Committee to have a key role in both the establishment and achievement of Company objectives shall be eligible to participate in the Plan. V. PLAN PERFORMANCE MEASURES Performance measures shall be established that consider shareholder and customer interests. These measures shall be evaluated annually based on achievement of specified goals. The performance measure reflective of shareholder's interest will be the percentage attainment of the earnings goal as specified in the annual operating plan. This measure will be applied at the corporate level for individuals, such as the Chief Executive Officer, or at the business unit level for individuals whose major or sole impact is on business unit results. Individual performance will be assessed based on the achievement of annually established individual objectives. Threshold, target and maximum award levels will be established annually for each performance measure and business unit. The Committee will retain the right to make all interpretations as to the actual attainment of the desired results and will determine whether any circumstances beyond the control of management need to be considered. VI. TARGET INCENTIVE AWARDS Target incentive awards will be expressed as a percentage of each participant's assigned salary grade market value (midpoint). These percentages shall vary by position and reflect larger reward opportunity for positions having greater effect on the establishment and accomplishment of the Company's or business unit's objectives. An exhibit showing the target awards as a percentage of salary grade market value (midpoint) for eligible positions will be attached to this Plan at the beginning of each Plan year. VII. INCENTIVE FUND DETERMINATION The target incentive fund is the sum of the individual target incentive awards for all eligible participants. The actual incentive fund may be lower, equal to, or greater than the target fund as determined by the Committee, based on actual performance as compared with approved performance objectives. At the close of each Plan year, the Chief Executive Officer of MDU Resources Group, Inc. will prepare an analysis showing the Company's and business unit's performance in relation to each of the performance measures employed. This will be provided to the Committee for review and comparison to threshold, target and maximum performance levels. In addition, any recommendations of the Chief Executive Officer will be presented at this time. The Committee will then determine the amount of the target incentive fund earned. VIII. INDIVIDUAL AWARD DETERMINATION Each individual participant's award will be based first upon the level of performance achieved by the Company or business unit and secondly based upon the individual's performance. The performance measures applicable for assessing individual performance will be established at the beginning of each Plan year. The assessment by the Committee, after consultation with the Chief Executive Officer, of achievement relative to the established performance measures, as determined by a percentage from 0 percent to 150 percent, will be applied to the Participant's target incentive award which has been first adjusted for Company or business unit performance. IX. PAYMENT OF AWARDS In order to receive an award under the Plan, the Participant must remain in the employment of the Company or business unit for the entire Plan year and be an employee on the payment date. An individual participant who transfers between the Company and business units may receive a prorated award at the discretion of the Committee. If employment is terminated prior to the payment date as a result of death, disability or retirement, or due to special circumstances as determined by the Committee, payment may be made after termination. Payments made under this Plan will not be considered part of compensation for pension purposes. Payments when made will be in cash, stock, or a combination thereof as determined appropriate by the Committee. Incentive awards may be deferred if the appropriate elections have been executed prior to the end of the Plan year. Deferred amounts will accrue interest at a rate determined annually by the Committee. In the event of a "change in control" (as defined by the Committee in its Rules and Regulations) then any award deferred by each Participant shall become immediately payable to the Participant in cash, together with accrued interest thereon to the date of payment. In the event the Participant files suit to collect the participant's deferred award then all of the court costs, other expenses of litigation, and attorneys' fees shall be paid by the Company in the event the Participant prevails upon any of the Participant's claims for payment of a deferred award. _________________________ Plan adopted November 4, 1982 Plan amended November 6, 1986 Plan amended May 15, 1996, effective January 1, 1996 Plan amended November 13, 1996, effective January 1, 1997 MDU RESOURCES GROUP, INC. EXECUTIVE INCENTIVE COMPENSATION PLAN RULES AND REGULATIONS The Compensation Committee of the Board of Directors of MDU Resources Group, Inc. (the "Company") adopted Rules and Regulations for the administration of the Management Incentive Compensation Plan (the "Plan") on February 9, 1983, following adoption of the Plan by the Board of Directors of the Company on November 4, l982. I. DEFINITIONS The following definitions shall be used for purposes of these Rules and Regulations and for the purposes of administering the Plan: 1. The "Committee" shall be the Compensation Committee of the Board of Directors of the Company. 2. The "Company" shall refer to MDU Resources Group, Inc. alone and shall not refer to its utility division or to any of its subsidiary corporations. 3. "Participants" for any Plan Year shall be those executives who have been approved by the Committee as eligible for participation in the Plan for such Plan Year. 4. "Payment Date" shall be the date set by the Committee for payment of awards, other than those awards deferred pursuant to section IX of the Plan and section VII of these Rules and Regulations. 5. The "Plan" shall refer to the Executive Incentive Compensation Plan. 6. The "Plan Year" shall be the calendar year. 7. "Change in control" shall mean the earlier of the following to occur: (a) the public announcement by the Company or by any person (which shall not include the Company, any subsidiary of the Company or any employee benefit plan of the Company or of any subsidiary of the Company) ("Person") that such Person, who or which, together with all Affiliates and Associates (within the meanings ascribed to such terms in Rule 12b-2 of the General Rules and Regulations under the Securities Exchange Act of 1934, as amended (17 C.F.R. 240.12b-2)) of such Person, shall be the beneficial owner of twenty percent (20%) or more of the voting stock then outstanding; (b) the commencement of, or after the first public announcement of any Person to commence, a tender or exchange offer the consummation of which would result in any Person becoming the beneficial owner of voting stock aggregating thirty percent (30%) or more of the then outstanding voting stock; (c) the announcement of any transaction relating to the Company required to be described pursuant to the requirements of Item 6(e) of Schedule 14A of Regulation 14A of the Securities and Exchange Commission under the Securities Exchange Act of 1934 (17 C.F.R. 240.14a-101, item 6(e)); (d) a proposed change in the constituency of the Board of Directors of the Company such that, during any period of two (2) consecutive years, individuals who at the beginning of such period constitute the Board of Directors of the Company cease for any reason to constitute at least a majority thereof, unless the election or nomination for election by the shareholders of the Company of each new Director was approved by a vote of at least two-thirds (2/3) of the directors then still in office who were members of the Board of Directors of the Company at the beginning of the period; or (e) any other event which shall be deemed by a majority of the Compensation Committee of the Board of Directors of the Company to constitute a "change in control." 8. The "Prime Rate" shall be the base rate on corporate loans posted by at least 75 percent of the nation's 30 largest banks as reported daily in The Wall Street Journal. II. ADMINISTRATION 1. The Committee shall have the full power to construe and interpret the Plan and to establish and to amend these Rules and Regulations for its administration. 2. No member of the Committee shall participate in a decision as to their own eligibility for, or award of, an incentive award payment. 3. Prior to the beginning of each Plan Year, the Committee shall approve a list of eligible executives and notify those so approved that they are eligible to participate in the Plan for such Plan Year. 4. Prior to the beginning of each Plan Year, the Committee shall draw up an Annual Operating Plan. The Annual Operating Plan shall include the Plan's performance measures and performance targets as well as the target incentive award levels for each salary grade covered by the Plan for the following Plan Year. The Annual Operating Plan, insofar as it is relevant to each individual Participant, shall be made available by the Committee to each Participant in the Plan at the beginning of each Plan Year. 5. The Committee shall have final discretion to determine actual award payment levels, method of payment, and whether or not payments shall be made for any Plan Year. However, unless the Plan's performance objectives are met for the Plan Year, no award shall be made for that Plan Year. Performance targets modified pursuant to section II of the Plan will be deemed performance targets for purposes of determining whether or not these targets have been met. III. PLAN PERFORMANCE MEASURES 1. The Committee shall establish the percentage attainment of earnings measure and the percentage attainment of individual goals measure. The Committee may establish more or fewer performance measures as it deems necessary. 2. The earnings measure shall be set by reference to the earnings of the Company or the individual business unit. 3. Individual performance will be assessed based on the achievement of annually established individual objectives. 4. Plan performance measures will be applied at the corporate level for individuals such as the Chief Executive Officer whose major or sole impact is Company-wide, or at the business unit level for individuals whose major or sole impact is on the business unit results. The Annual Operating Plan shall contain a list of individuals to whom the Plan performance measures will be applied at the corporate level and a list of those individuals for whom the Plan performance measures will be applied at the business unit level. The relevant business unit for each individual will be identified. 5. The Committee shall set threshold, target and maximum award levels for the performance measures, for each business unit, and for the Company. Those levels shall be included in the Annual Operating Plan. 6. The Committee will retain the authority to determine whether or not the actual attainment of these measures has been made. IV. TARGET INCENTIVE AWARDS 1. Target incentive awards will be a percentage of each Participant's assigned salary grade midpoint. 2. Target incentive awards shall be set by the Committee annually and will be included in the Annual Operating Plan. V. INCENTIVE FUND DETERMINATION 1. The target incentive fund is the sum of the individual target incentive awards for all eligible Participants. 2. The actual incentive fund will be determined by the Committee, based on actual performance as compared with the approved performance measures. 3. As soon as practicable following the close of each Plan Year, the Chief Executive Officer will provide the Committee with an analysis showing the Company's and each relevant business unit's performance in relation to both of the performance measures. The Committee will review the analysis and determine, in its sole discretion, the amount of the actual incentive fund. 4. In determining the actual incentive fund, the Committee may consider any recommendations of the Chief Executive Officer. VI. INDIVIDUAL AWARD DETERMINATION 1. The Committee shall have the sole discretion to determine each individual Participant's award. The Committee's decision will be based first upon the level of performance achieved by the Company or business unit and second upon the individual's performance. 2. The Committee, after consultation with the Chief Executive Officer, shall set the award as a percentage from 0 percent to 150 percent of the Participant's target incentive award, adjusted for Company or business unit performance. VII. PAYMENT OF AWARDS 1. On the date the Committee determines the awards to be made to individual Participants, it shall also establish the Payment Date. 2. In order to receive an award under the Plan, a Participant must remain in the employment of the Company for the entire Plan Year and be an employee on the Payment Date. 3. If employment is terminated prior to Payment Date as a result of death, disability or retirement, or due to special circumstances as determined by the Committee in its sole discretion, payment may be made after termination. 4. Payments of the awards may be made in cash, stock or a combination thereof as determined by the Committee. Such payments shall be made on the Payment Date unless the Participant has deferred, in whole or in part, the receipt of the award by making an election on the deferral form attached hereto, prior to the end of the Plan Year immediately preceding the Payment Date. 5. In the event a Participant has elected to defer receipt of all or a portion of the award, the Company shall set up an account in their name. The amount of their award to the extent deferred will be credited to the participant's account on the Payment Date. 6. The balance credited to an account of a Participant who has elected to defer receipt of an award will be an unsecured, unfunded obligation of the Company. 7. Interest shall accrue on the balance credited to a Participant's account. The rate of interest shall be the Prime Rate plus 1 percentage point as reported on the last Friday in January of each year. Interest on the balance in an account shall accrue at the rate so determined from the Payment Date immediately following the determination to the Payment Date of the following year. 8. Interest shall be credited to the account on the day preceding Payment Date and shall be calculated on the balance in the Participant's account as of that date. 9. A Participant may elect to defer any percentage, not to exceed l00, of an annual award. 10. A Participant electing to defer any part of an award must elect one of the following dates for payment: (1) Retirement date; (2) Payment Date next following termination of employment; or (3) Payment Date of the fifth year following the year in which the award may be made. 11. A Participant may elect to receive the deferred amounts accumulated in the Participant's account in monthly installments, not to exceed 120. In the event the Participant elects to receive the amounts in the Participant's account in more than one installment, interest shall continue to accrue on the balance remaining in their account at the applicable rate or rates determined annually by the Committee. 12. In the event of the death of a Participant in whose name a deferred account has been set up, the Company shall, within six months thereafter, pay to the Participant's estate or the designated beneficiary the entire amount in the deferred account. 13. In the event of a "change in control" then any award deferred by each Participant shall become immediately payable to the Participant. In the event the Participant files suit to collect a deferred award then all of the Participant's court costs, other expenses of litigation, and attorneys' fees shall be paid by the Company in the event the Participant prevails upon any of the Participant's claims for payment. __________________________ Rules and Regulations adopted November 4, 1982 Rules and Regulations amended August 5, 1987 Rules and Regulations amended February 9, 1989 Rules and regulations amended May 15, 1996, effective January 1, 1996 Rules and regulations amended November 13, 1996, effective January 1, 1997 EX-10.D 4 SUPPLEMENTAL INCOME SECURITY PLAN MDU RESOURCES GROUP, INC. SUPPLEMENTAL INCOME SECURITY PLAN (As Amended and Restated Effective January 1, 1997) TABLE OF CONTENTS INTRODUCTION ARTICLE I -- DEFINITIONS ARTICLE II -- ELIGIBILITY ARTICLE III -- SUPPLEMENTAL DEATH AND RETIREMENT BENEFITS ARTICLE IV -- EXCESS RETIREMENT BENEFITS ARTICLE V -- DISABILITY BENEFITS ARTICLE VI -- MISCELLANEOUS ARTICLE VII -- ADDITIONAL AFFILIATED COMPANIES INTRODUCTION The objective of the MDU Resources Group, Inc. Supplemental Income Security Plan (the "Plan") is to provide certain levels of survivor benefits and retirement income for a select group of management or highly compensated employees and their families. Eligibility for participation in this Plan shall be limited to management or highly compensated employees who are selected by the Chief Executive Officer of MDU Resources, Inc. (the "Company"). This Plan became effective January 1, 1982, has been amended from time to time thereafter, and has been amended and restated effective January 1, 1997. The Plan is intended to constitute an unfunded "excess benefit plan" as defined in Section 3(36) of the Employee Retirement Income Security Act of 1974, as amended ("ERISA"), to the extent it provides benefits that would be paid under one or more of the tax-qualified pension plans of the Company or certain of its subsidiaries but for certain limitations set forth under the Internal Revenue Code of 1986, as amended (the "Code"), and constitutes an unfunded plan of deferred compensation maintained by the Company primarily for the purpose of providing non- elective deferred compensation for a select group of management or highly compensated employees. ARTICLE I -- DEFINITIONS Unless a different meaning is plainly implied by the context, the following terms as used in this Plan shall have the following meanings: 1.1 "Administrator" means the Chief Executive Officer of the Company or any other person to whom the Chief Executive Officer of the Company has delegated the authority to administer the Plan. The Manager of the Corporate Human Resources Department of the Company is initially delegated the authority to perform the administrative responsibilities required under the Plan. 1.2 "Affiliated Company" means any current or future corporation which (i) is in a controlled group of corporations (within the meaning of Section 414(b) of the Code) of which the Company is a member and (ii) has been approved by the Chief Executive Officer of the Company to adopt the Plan for the benefit of its Employees. 1.3 "Beneficiary" means an individual or individuals, any entity or entities (including corporations, partnerships, estates or trusts) that shall be entitled to receive benefits payable pursuant to the provisions of this Plan by virtue of a Participant's death; provided, however, that if more than one such person is designated as a Beneficiary hereunder, each such person's proportionate share of the death benefit hereunder must clearly be set forth in a written statement of the Participant received by and filed with the Administrator prior to the Participant's death. If such proportionate share for each Beneficiary is not set forth in the designation, each Beneficiary shall receive an equal share of the death benefits provided hereunder. 1.4 "Company" means MDU Resources Group, Inc., and its successors, if any. 1.5 "Effective Date" of the Plan means January 1, 1982. The Effective Date of this amendment and restatement of the Plan is January 1, 1997. 1.6 "Eligible Retirement Date" means the First Eligible Retirement Date and the last day of each subsequent calendar month. 1.7 "Employee" means each person actively employed by an Employer, as determined by such Employer in accordance with its practices and procedures. 1.8 "Employer" means the Company and any Affiliated Company which shall adopt this Plan with respect to its Employees with the prior approval of the Company as set forth in Article 7 of the Plan. 1.9 "First Eligible Retirement Date" for a Participant means the last day of the month during which such Participant is both no longer actively employed by any Employer and has attained at least age 65. 1.10 "Limitation on Benefits" shall mean the statutory limitation on the maximum benefit that may be payable to participants under a Pension Plan due to the application of certain provisions contained in the Code. 1.11 "Participant" means a present or former management or highly compensated Employee selected by the Chief Executive Officer of the Company to receive benefits under this Plan. An Employee will become a Participant at the time such Employee commences participation hereunder pursuant to the provisions of Section 2.1 hereof. 1.12 "Pension Plan" means the MDU Resource Group, Inc. Pension Plan for Non-Bargaining Unit Employees, the Williston Basin Interstate Pipeline Company Pension Plan for Non-Bargaining Unit Employees, or the Knife River Coal Mining Company Salaried Employees' Pension Plan, as in effect on the Effective Date and as amended from time to time. 1.13 "Plan" means the Plan designated as the MDU Resources Group, Inc. Supplemental Income Security Plan, as embodied herein, and any amendments thereto. 1.14 "Plan Year" means the calendar year. The first Plan Year for this Plan shall be the 1982 calendar year. 1.15 "Salary" means annual base earnings payable by an Employer to a Participant excluding (i) bonuses, (ii) incentive compensation, and (iii) any other form of supplemental income. 1.16 "Standard Actuarial Factors" means, with respect to a Participant, the actuarial factors and assumptions used for the calculation of actuarial equivalents under the Pension Plan under which the Participant actively participates from time to time. 1.17 "Standard Life Insurance" means life insurance that could be purchased from a commercial life insurance company at standard rates without a surcharge assessed, based on an individual's general good health. 1.18 "Standard Underwriting Factors" means life insurance rating factors utilized by a commercial life insurance company selected by the Chief Executive Officer of the Company which are based on the risk assessment classifications utilized by such insurer to determine if an applicant qualifies for insurance at standard rates or if health or other factors might require a surcharge. 1.19 "Year of Participation" means each Plan Year of participation in the Plan by a Participant while actively employed by one or more of the Employers (including years while such Participant is qualified as totally disabled under the Employer's disability plan), as determined in the sole discretion of the Administrator. ARTICLE II -- ELIGIBILITY 2.1 Eligibility for Participation. The Chief Executive Officer of the Company shall determine which management and/or highly compensated Employees may be eligible to participate in the Plan. General criteria for initial consideration of an Employee includes, but is not limited to, the following: (A) either an officer (excluding assistant secretary or assistant treasurer), or a senior management employee of an employer earning a base salary exceeding a threshold amount as determined by the Chief Executive Officer of the Company; (B) an executive who makes a significant contribution to the Company's success and profitability; (C) an executive in a business unit where benefits of this nature are a common practice, or there is a specific need to recruit and retain key executives; and (D) the expectation that participation in the Plan will not exceed four percent of the total employment of the Company and affiliated companies. Each Employee who is selected as eligible to participate hereunder and who meets the requirements for participation set forth under Section 2.2 hereof shall commence participation on the first day of the Plan Year coincident with or next following the date of such Employee's selection. 2.2 Requirements for Participation. In order to be eligible to participate in the Plan, an Employee selected by the Chief Executive Officer of the Company must (i) be actively at work for one or more of the Employers; (ii) have a current state of health and physical condition that would satisfy customary requirements for insurability under Standard Life Insurance; provided, however, that no provision of this Plan shall be construed or interpreted to limit participation in the Plan in contravention of the Americans With Disabilities Act and related federal and state laws; and (iii) consent to supply information or to otherwise cooperate as necessary to allow the Company to obtain life insurance on behalf of such Employee (as set forth under Section 6.3 of the Plan). 2.3 Eligibility for Benefits. Subject to the provisions of Articles III and IV hereof, Participants who terminate their employment with an Employer subsequent to becoming vested in a retirement benefit under a Pension Plan shall be eligible to receive a benefit under this Plan. Plan benefits may commence (i) as of the earlier to occur of (A) the first day of the month following the date of the Participant's death or (B) if the Participant who elects to receive retirement benefits under Article 3 hereof, the Participant's First Eligible Retirement Date, for purposes of the benefits payable under Article III of the Plan, and (ii) at the time benefit payments commence to the Participant under a Pension Plan, for purposes of the benefits payable under Article IV of the Plan. 2.4 Relationship to Other Plans. Participation in the Plan shall not preclude or limit the participation of the Participant in any other benefit plan sponsored by one or more of the Employers for which such Participant otherwise would be eligible. However, any benefits payable under this Plan shall not be deemed salary or compensation to the Participant for purposes of determining benefits under any other employee benefit plan maintained by one or more of the Employers. 2.5 Forfeiture of Benefits. Notwithstanding any provision of this Plan to the contrary, if any Participant is discharged from employment by one or more of the Employers for cause due to willful misconduct, dishonesty, or conviction of a crime or felony, all as determined at the sole discretion of the Chief Executive Officer of the Company the rights of such Participant (or any Beneficiary of such Participant) to any present or future benefit under this Plan shall be forfeited to the extent not prohibited by applicable law. ARTICLE III -- SUPPLEMENTAL DEATH AND RETIREMENT BENEFITS 3.1 Amount of Benefit. (a) Subject to the provisions of Section 3.3 of the Plan, the monthly supplemental death and/or retirement benefits payable on behalf of (or to) a Participant as of such Participant's date of death (or First Eligible Retirement Date) will be an amount determined at the sole discretion of the Chief Executive Officer of Company at the time of the Participant's commencement of participation in the Plan, as may be adjusted from time to time thereafter by the Chief Executive Officer of the Company. However, in no event will a Participant be entitled to have a monthly supplemental death benefit paid on such Participant's behalf (or be entitled to receive a monthly supplemental retirement benefit) that exceeds the Monthly Death Benefit or Monthly Retirement Benefit (as applicable) corresponding to the Participant's Salary in effect at the date such initial or revised benefit determination is to be effective, all as set forth in the applicable Appendix hereto. Benefits for Participants retiring or dying after December 31, 1989, and prior to January 1, 1997, shall be determined in accordance with Appendix A. Benefits for Participants retiring or dying after December 31, 1996, shall be determined in accordance with Appendix B; provided, however, that benefits for each such individual who also was a Participant on December 31, 1996, shall be determined in accordance with Appendix A or Appendix B, whichever such Appendix provides for the greatest amount of benefits. Changes in Salary do not automatically result in changes to a Participant's level of benefits. (b) Participants who died, terminated employment with, or retired from, the Employers prior to January 1, 1990, will receive benefits hereunder in accordance with the terms of the Plan as in effect at the time of the Participant's death, termination of employment or retirement from the Employers. (c) The benefit amounts determined by the Chief Executive Officer of the Company pursuant to Section (a) above are based on the assumption that each Participant's health and physical condition at the time of such Participant's commencement of participation in the Plan meets customary requirements for Standard Life Insurance. Benefits under the Plan may be reduced by the Chief Executive Officer of the Company within a reasonable period following the establishment of such benefit level in accordance with Standard Underwriting Factors, but only with respect to that portion of the monthly death or retirement benefit for which the criteria for health and physical condition are not met. Participants will be notified of any such reduction within a reasonable period following participation in the Plan. Once retirement benefits have been reduced under this Section 3.1, such benefits shall not be further reduced for the remainder of the Participant's participation in the Plan. 3.2 Amount of Monthly Benefit for Retirement or Death Prior to Completing at Least 10 Years of Participation. If a Participant retires or terminates employment with an Employer (for reasons other than the Participant's death) before the Participant completes at least 10 Years of Participation, the monthly death and/or retirement benefits to which such Participant otherwise would be entitled under the terms of Section 3.1 hereof shall be reduced as follows: Years of Participation Percent of Section 3.1 Completed by the Participant Benefits Payable Less than 3 years 0% 3 years but less than 5 years 10% 5 years but less than 7 years 25% 7 years but less than 9 years 50% 9 years but less than 10 years 75% 10 years or more 100% 3.3 Payment of Monthly Benefit. Upon attainment of age 65 or, as of such Participant's First Eligible Retirement Date (if later), a Participant wil be entitled to determine the form of benefit payable to such Participant under subsection (a) hereof, and the date of commencement of such benefits, subject to the approval of the Chief Executive Officer of the Company, in accordance with the terms of the Plan. (a) The Participant may elect to receive: (i) a monthly death benefit in amounts determined pursuant to Section 3.1 hereof, multiplied by the appropriate percentage amount set forth in Section 3.2, or (ii) in lieu of any death benefits under this Plan a monthly retirement benefit determined in accordance with Section 3.1, multiplied by the appropriate percentage amount set forth in Section 3.2, with no death benefit, or (iii) a percentage of each benefit described in subsections(a)(i) and (a)(ii) above. The percentage of each benefit must be in even increments of ten percent (10%). (b) A Participant must select one of the options under subsection (a) above. If, in accordance with Sections 3.3(a)(ii) or (iii), a Participant has elected to receive less than one hundred percent (100%) of such Participant's monthly retirement benefit, the Participant may subsequently elect to begin receiving an increased retirement benefit except that there may be no more than two(2) such increases during the Participant's lifetime, and no more than one (1) such increase during any calendar year. Any such increase in retirement benefit payments will result in a reduction in death benefits equal, when expressed as a percentage amount, to the percentage increase in retirement benefit. Participants shall not be entitled to decrease retirement benefit payments. (c) Elections under this Section 3.3 must be communicated in writing to the Administrator and will be effective as of the first day of the first month following the Administrator's receipt and the approval of such request by the Chief Executive Officer of the Company. 3.4 Payment of Monthly Death and Retirement Benefits. (a) Death Benefits. Any death benefits payable with respect to a Participant pursuant to Sections 3.3(a)(i) or 3.3(a)(iii) shall commence on the first day of the calendar month next following the date of the Participant's death and shall be payable in monthly installments for a period of 180 months. (b) Retirement Benefits. The monthly retirement benefits under this Plan shall commence on the Eligible Retirement Date selected by the Participant (upon 30 day's written notice to the Administrator) and will be payable to such Participant in monthly installments for a period of 180 months. In the event the Participant dies prior to the completion of such 180-month payment period, the balance of such retirement benefits shall be paid to the Participant's Beneficiary at such times and in such amounts as if the Participant had not died, such payment being made in addition to any death benefits payable under Sections 3.3(a)(i) or (iii) hereof. To the extent a Participant elects to commence receiving increased retirement benefits pursuant to Section 3.3(b), the amount of increase of retirement benefits shall be in the form of a monthly benefit payable for a separate 180-month period. (c) Method of Payment. Notwithstanding the provisions of subsections (a) and (b) of this Section 3.4, the Chief Executive Officer of the Company reserves the right to pay benefits in the form of an actuarially equivalent single sum (as determined by the Administrator) when retirement or death benefits are payable due to termination of employment, excluding disability, or death prior to the Participant's attainment of age 55. 3.5 Exclusions and Limitations. (a) No death benefits will be payable with respect to a Participant in the event of such Participant's death by suicide within two (2) years after commencement of participation in the Plan, and no benefit increase will apply in the event of any such Participant's death by suicide within two (2) years after such Participant becomes eligible for an increase in death benefits. (b) In the event that a Participant misrepresents any health or physical condition at the time of commencement of participation in the Plan or at the time of a retirement or death benefit increase, no retirement or death benefit or retirement or death benefit increase will be payable under the Plan within two (2) years of such misrepresentation. 3.6 Death of a Beneficiary. (a) In the event any Beneficiary predeceases the Participant, is not in existence, is not ascertainable, or is not locatable as of the date benefits under the Plan become payable to such Beneficiary, Plan benefits shall be paid to such contingent Beneficiary or Beneficiaries as shall have been named by the Participant on the Participant's most recent Beneficiary election form that has been received and filed with the Administrator prior to the Participant's death. If no contingent Beneficiary has been named, the contingent Beneficiary shall be the Participant's estate. (b) In the event any Beneficiary dies after commencing to receive monthly benefits under the Plan but prior to the payment of all monthly benefits to which such Beneficiary is entitled, remaining benefits shall be paid to a beneficiary designated by the deceased Beneficiary (the "Secondary Beneficiary"), provided such designation has been received and filed with the Administrator prior to the death of the Beneficiary. If no such person has been designated by the deceased Beneficiary, the Secondary Beneficiary shall be the estate of the Beneficiary. In the event the Secondary Beneficiary shall die prior to the payment of all benefits to which such Secondary Beneficiary is entitled, the remainder of such payments shall be made to such Secondary Beneficiary's estate. If the Administrator is in doubt as to the right of any person to receive benefits under the Plan, the Administrator may retain such amount, without liability for any interest thereon, until the rights thereto are determined, or the Administrator may pay such amount into any court of competent jurisdiction and such payment shall be a complete discharge of the liability of the Plan and the Employer therefor. 3.7 Discretion As To Benefit Amount. Notwithstanding the foregoing, the Chief Executive Officer of the Company may, with full and complete discretion, disregard Standard Underwriting Factors and customary requirements for Standard Life Insurance in establishing and/or increasing the amount of any Participant's retirement or death benefit under the Plan. 3.8 Suspension of Benefits Upon Reemployment. Employment with any Employer subsequent to the commencement of retirement benefits under this Article III may, at the sole discretion of the Chief Executive Officer of the Company, result in the suspension of such benefits for the period of such employment or reemployment. ARTICLE IV -- EXCESS RETIREMENT BENEFITS 4.1 Participation. Benefits under this Article IV shall be payable only to those Participants whose benefits under the Pension Plan under which they otherwise participate commence prior such Participant's attainment of age 65 and are reduced or limited by reason of the Limitation on Benefits. Benefits under this Article IV (i) shall be payable only for such period that the benefits under the Pension Plan are actually reduced or limited and (ii) shall terminate as of the last day of the month immediately preceding the month during which occurs the Participant's sixty-fifth (65th) birthday. Furthermore, benefits under this Article IV also shall be payable only to those Participants who are active Employees on or after January 1, 1997. 4.2 Amount and Method of Payment. (a) Amount of Benefit. The amount, if any, of the monthly benefit payable to or on account of a Participant pursuant to this Article IV shall equal the excess of (i) over (ii) where: (i) equals the amount of monthly retirement benefits which would be provided to the Participant under the Pension Plan without regard to the Limitation on Benefits; and (ii) equals the amount of monthly retirement benefits payable to such Participant under the Pension Plan due to the application of the Limitation on Benefits; provided, however, that no benefit shall be payable to a Participant under this Article IV unless the amount of such monthly benefit is at least fifty dollars ($50). The benefit amount provided under this Section 4.2(a) shall be determined with reference to the form of benefit determined under Section 4.2(c) hereof and shall be calculated in accordance with the Standard Actuarial Factors utilized under the Pension Plan. (b) Vesting. The amount of benefits payable to a Participant under this Article IV shall be subject to the vesting schedule set forth in the Pension Plan. A Participant shall be vested in benefits under this Article IV to the same extent as such Participant is vested in benefits under the Pension Plan. (c) Payment of Benefit. The benefits provided under this Article IV shall be paid to each such Participant, surviving spouse (as defined under the Pension Plan) or joint annuitant (as defined under the Pension Plan) at the same time and in the same form and manner as benefits are payable under the Pension Plan. Payments shall be made in accordance with, and subject to, the terms and conditions of the Pension Plan; provided, however, that no spousal consent shall be required to commence any form of payment under this Article IV. (d) Duration of Payments. Subject to Section 4.2(c), benefits provided under this Article IV shall commence at the same time as payments commence under the Pension Plan, and shall continue to age 65 or the death of the Participant, if prior to age 65, and, if applicable, in a reduced amount until the death of the Participant's lawful spouse or joint annuitant, whichever is applicable for those Participants receiving benefits under Appendix B. (e) Treatment During Subsequent Employment. Employment with any Employer subsequent to the commencement of benefits under this Article IV will result in the suspension of such benefits for the period of such employment or reemployment to the extent forth under the Pension Plan. (f) Necessity of Actual Reduction. Notwithstanding any other provision of this Plan, no amount shall be payable under this Article IV unless the Participant's monthly benefit paid under the Pension Plan is actually reduced because of application of the Limitation on Benefits. Benefits payable to a Participant under this Article IV shall not duplicate benefits payable to such Participant from any other plan or arrangement of the Company. In the event the Secretary of the Treasury or a change in law liberalizes the limitations applicable to determining the Limitation on Benefits such that a Participant may receive additional benefits under the Pension Plan, and the Pension Plan provides for the payment of such additional benefits to the Participant, the amount payable under this Article IV shall be reduced by a corresponding amount. ARTICLE V -- DISABILITY BENEFITS 5.1 Monthly Disability Benefit. (a) If a Participant becomes totally disabled following commencement of participation in the Plan, the Participant shall continue to receive credit for Years of Participation under the Plan for so long as the Participant is totally disabled and such Participant's employment with the Employer has not terminated. Following termination of the Participant's employment with the Employer, the Participant's monthly retirement benefits under Article III of the Plan shall commence beginning on or after the Participant's First Eligible Retirement Date. (b) A Participant is "totally disabled" if such Participant is disabled within the meaning of the applicable long-term disability plan sponsored by such Participant's Employer. (c) If a Participant who terminates employment with the Company due to total disability dies while totally disabled and before attaining age 65, any death benefit payable to the Participant's Beneficiary will be determined and paid in accordance with the terms of Article III. ARTICLE VI -- MISCELLANEOUS 6.1 Amendment and Termination. Any action to amend, modify, suspend or terminate the Plan may be taken at any time, and from time to time, by resolution of the Board of Directors of the Company (or any person or persons duly authorized by resolution of the Board of Directors of the Company to take such action) in its sole discretion and without the consent of any Participant or Beneficiary, but no such action shall retroactively reduce any benefits accrued by any Participant under this Plan prior to the time of such action. 6.2 No Guarantee of Employment. Nothing contained herein shall be construed as a contract of employment between a Participant and any Employer or shall be deemed to give any Participant the right to be retained in the employ of any Employer. 6.3 Funding of Plan and Benefit Payments. This Plan is unfunded within the meaning of ERISA. Each Employer will make Plan benefit payments from its general assets. Each Employer may purchase policies of life insurance on the lives of Plan Participants and to refuse participation in the Plan to any Employee who, if requested to do so, declines to supply information or to otherwise cooperate so that the Employer may obtain life insurance on behalf of such Participant. The Employer will be the owner and the beneficiary of any such policy, and Plan benefits will be neither limited to nor secured by any such policy or its proceeds. Participants and their Beneficiaries shall have no right, title or interest in any such life insurance policies, in any other assets of any Employer or in any investments any Employer may make to assist it in meeting its obligations under the Plan. All such assets shall be solely the property of such Employer and shall be subject to the claims of such Employer's general creditors. There are no assets of any Employer that are identified or segregated for purposes of the payment of any benefits under this Plan. To the extent a Participant or any other person acquires a right to receive payments from an Employer under the Plan, such right shall be no greater than the right of any unsecured general creditor of such Employer and such person shall have only the unsecured promise of the Employer that such payments shall be made. 6.4 Payment Not Assignable. Except in the case of a Qualified Domestic Relations Order described under Code Section 414(p), Participants and their Beneficiaries shall not have the right to alienate, anticipate, commute, sell, assign, transfer, pledge, encumber or otherwise convey the right to receive any payments under the Plan, and any payments under the Plan or rights thereto shall not be subject to the debts, liabilities, contracts, engagements or torts of Participants or their Beneficiaries nor to attachment, garnishment or execution, nor shall they be transferable by operation of law in the event of bankruptcy or insolvency. Any attempt, whether voluntary or involuntary, to effect any such action shall be null, void and of no effect. 6.5 Applicable Law. The Plan and all rights hereunder shall be governed by and construed according to the laws of the State of North Dakota, except to the extent such laws are preempted by the laws of the United States of America. 6.6 Claims Procedure. (a) Participants and Beneficiaries eligible for benefits under this Plan, or any person duly authorized by them, have the right under ERISA and the Plan to file a written claim to the Administrator for payment of such benefits. (b) If the claim is denied in whole or in part, the claimant will receive written notice of the Administrator's decision, including the specific reason for the decision, within 90 days after the Administrator received the claim. If the Administrator needs more than 90 days to make a decision, the Administrator will notify the individual in writing within the initial 90-day period. An additional 90 days may be taken if the Administrator sends this notice. The extension notice will show the date by when the Administrator's decision will be sent. 6.7 Plan Administration. (a) The Plan shall be administered by the Administrator. The Administrator shall serve as the final review under the Plan and shall have sole and complete discretionary authority to determine conclusively for all persons, and in accordance with the terms of the documents or instruments governing the Plan, any and all questions arising from the administration of the Plan and interpretation of all Plan provisions. The Administrator shall make the final determination of all questions relating to participation of employees and eligibility for benefits, and the amount and type of benefits payable to any Participant or Beneficiary. In no way limiting the foregoing, the Administrator shall have the following specific duties and obligations in connection with the administration of the Plan: (i) To promulgate and enforce such rules, regulations and procedures as may be proper for the efficient administration of the Plan; (ii) To determine all questions arising in the administration, interpretation and application of the Plan, including questions of eligibility and of the status and rights of Participants and any other persons hereunder; (iii) To decide any dispute arising hereunder; provided, however, that the Administrator shall not participate in any matter involving any questions relating solely to the Administrator's own participation or benefit under this Plan; (iv) To advise the Boards of Directors of the Employers regarding the known future need for funds to be available for distribution; (v) To correct defects, supply omissions and reconcile inconsistencies to the extent necessary to effectuate the Plan; (vi) To compute the amount of benefits and other payments which shall be payable to any Participant or Beneficiary in accordance with the provisions of the Plan and to determine the person or persons to whom such benefits shall be paid; (vii) To make recommendations to the Board of Directors of the Company with respect to proposed amendments to the Plan; (viii) To file all reports with government agencies, Participants and other parties as may be required by law, whether such reports are initially the obligation of the Employers, or the Plan; (ix) To engage an actuary to the Plan, if necessary, and to cause the liabilities of the Plan to be evaluated by such actuary; and (x) To have all such other powers as may be necessary to discharge its duties hereunder. (b) Decisions by the Administrator shall be final, conclusive and binding on all parties and not subject to further review. (c) The Administrator may employ attorneys, consultants, accountants or other persons (who may be attorneys, consultants, actuaries, accountants or persons performing other services for, or are employed by, any Employer or any affiliate of any Employer), and the Administrator, the Employers and their other officers and directors shall be entitled to rely upon the advice, opinions or valuations of any such persons. No member of the Board of Directors of any Employer, the Chief Executive Officer of the Company, the Administrator, nor any other officer, director or employee of the Company or of any Employer acting on behalf of the Board of Directors of any Employer or the Chief Executive Officer of the Company or the Administrator, shall be personally liable for any action, determination or interpretation taken or made in good faith with respect to the Plan, and all members of the Boards of Directors of the Employers, the Chief Executive Officer of the Company and the Administrator and each officer or employee of the Company or of an Employer acting on their behalf shall be fully indemnified and protected by the Company for all costs, liabilities and expenses (including, but not limited to, reasonable attorneys' fees and court costs) relating to any such action, determination or interpretation. 6.8 Binding Nature. This Plan shall be binding upon and inure to the benefit of the Employers and their successors and assigns and to the Participants, their Beneficiaries and their estates. Nothing in this Plan shall preclude any Employer from consolidating or merging into or with, or transferring all or substantially all of its assets to another company or corporation, whether or not such other company or corporation assumes this Plan and any obligation of the Employer hereunder. 6.9 Withholding Taxes. The Employers may withhold from any benefits payable under this Plan all Federal, State, city or other taxes as shall be required pursuant to any law or governmental regulation or ruling. 6.10 Action Affecting Chief Executive Officer. To the extent any action required to be taken by the Chief Executive Officer of the Company would decrease, increase, accelerate, delay or otherwise materially impact such individual's benefits under the Plan, such action shall be taken instead by the Compensation Committee of the Board of Directors of the Company. 6.11 Payments Due Missing Persons. The Administrator shall make a reasonable effort to locate all persons entitled to benefits (including retirement benefits and death benefits for Beneficiaries) under the Plan; however, notwithstanding any provisions of this Plan to the contrary, if, after a period of five years from the date such benefits first become due, any such persons entitled to benefits have not been located, their rights under the Plan shall stand suspended. Before this provision becomes operative, the Administrator shall send a certified letter to all such persons at their last known address advising them that their benefits under the Plan shall be suspended. Any such suspended amounts shall be held by the Employer for a period of three additional years (or a total of eight years from the time the benefits first became payable) and thereafter such amounts shall be forfeited and non-payable. 6.12 Liability Limited. Neither the Employers, the Administrator, nor any agents, employees, officers, directors or shareholders of any of them, nor any other person shall have any liability or responsibility with respect to this Plan, except as expressly provided herein. 6.13 Incapacity. If the Administrator shall receive evidence satisfactory to it that a Participant or Beneficiary entitled to receive any benefit under the Plan is, at the time when such benefit becomes payable, a minor or is physically or mentally incompetent to receive such benefit and to give a valid release therefor, and that another person or an institution is then maintaining or has custody of such Participant or Beneficiary and that no guardian, committee or other representative of the estate of such Participant or Beneficiary shall have been duly appointed, the Administrator may make payment of such benefit otherwise payable to such Participant or Beneficiary (or to such guardian, committee or other representative of person's estate) to such other person or institution, and the release of such other person or institution shall be a valid and complete discharge for the payment of such benefit. 6.14 Plurals. Where appearing in the Plan, the singular shall include the plural, and vice versa, unless the context clearly indicates a different meaning. 6.15 Headings. The headings and sub-headings in this Plan are inserted for the convenience of reference only and are to be ignored in any construction of the provisions hereof. 6.16 Severability. In case any provision of this Plan shall be held illegal or void, such illegality or invalidity shall not affect the remaining provisions of this Plan, but shall be fully severable, and the Plan shall be construed and enforced as if said illegal or invalid provisions had never been inserted herein. 6.17 Payment of Benefits. All amounts payable hereunder may be paid directly by the Employer or pursuant to the terms of the grantor trust, if any, established as a funding vehicle for benefits provided hereunder. ARTICLE VII -- ADDITIONAL AFFILIATED COMPANIES 7.1 Participation in the Plan. (a) Any Employer may become an Affiliated Company with respect to this Plan with the consent of the Chief Executive Officer of the Company, upon the following conditions: (i) such Employer shall make, execute and deliver such instruments as the Company requires; and (ii) such Employer shall designate the Company, the Chief Executive Officer of the Company and the Administrator, as its agents for purposes of this Plan. (b) Any such Affiliated Company may by action of its Board of Directors withdraw from participation, subject to approval by the Chief Executive Officer of the Company. 7.2 Effect of Participation. Each Affiliated Company which with the consent of the Chief Executive Officer of the Company complies with Section 7.1(a) shall be deemed to have adopted this Plan for the benefit of its Employees who participate in this Plan. IN WITNESS WHEREOF, the Company, as the sponsoring employer of the Plan, has caused this Plan document to be duly executed by its President and Chief Executive Officer on this 14 day of November, 1996. MDU RESOURCES GROUP, INC. By: /s/ H. J. Mellen, Jr. H. J. Mellen, Jr. President and Chief Executive Officer APPENDIX A Monthly Monthly Retirement Level Salary Death Benefit Benefit* D $ 50,000 - $ 59,999 $ 3,456 $ 1,728 E $ 60,000 - $ 74,999 $ 4,320 $ 2,160 F $ 75,000 - $ 99,999 $ 5,760 $ 2,880 G $100,000 - $124,999 $ 7,200 $ 3,600 H $125,000 - $149,999 $ 8,640 $ 4,320 I $150,000 - $174,999 $10,080 $ 5,040 J $175,000 - $199,999 $11,520 $ 5,760 K $200,000 - $224,999 $12,960 $ 6,480 L $225,000 - $249,999 $14,400 $ 7,200 M $250,000 - $274,999 $15,840 $ 7,920 N $275,000 - $299,999 $17,280 $ 8,640 O $300,000 - $324,999 $18,720 $ 9,360 P $325,000 - $349,999 $20,160 $10,080 All benefits are paid for a maximum of 180 months. * This amount shall be lesser than the net present value of the death benefit, as determined at the sole discretion of the Administrator. APPENDIX B Monthly Monthly Death Retirement Level Salary Benefit Benefit* D $ 50,000 - $ 59,999 $ 2,660 $ 1,330 E $ 60,000 - $ 69,999 $ 3,600 $ 1,800 F $ 75,000 - $ 99,999 $ 5,160 $ 2,580 G $100,000 - $124,999 $ 7,200 $ 3,600 H $125,000 - $149,999 $ 8,940 $ 4,470 I $150,000 - $174,999 $10,720 $ 5,360 J $175,000 - $199,999 $12,500 $ 6,250 K $200,000 - $224,999 $14,600 $ 7,300 L $225,000 - $249,999 $16,430 $ 8,215 M $250,000 - $274,999 $18,250 $ 9,125 N $275,000 - $299,999 $20,950 $10,475 O $300,000 - $324,999 $24,290 $12,145 P $325,000 - $349,999 $27,340 $13,670 Q $350,000 - $399,999 $32,220 $16,110 R $400,000 - $449,999 $39,050 $19,525 S $450,000 - $499,999 $45,700 $22,850 T $500,000+ $52,400 $26,200 All benefits are paid for a maximum of 180 months. * This amount shall be lesser than the net present value of the death benefit, as determined at the sole discretion of the Administrator. EX-12 5 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES MDU RESOURCES GROUP, INC. COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES Years Ended December 31, 1996 1995 1994 1993 1992 (In thousands of dollars) Earnings Available for Fixed Charges: Net Income per Consolidated Statements of Income $45,470 $41,633 $39,845 $38,817* $35,371 Income Taxes 16,087 23,057 18,833 19,982* 10,900 61,557 64,690 58,678 58,799 46,271 Rents (a) 1,031 894 878 871 504 Interest (b) 34,101 29,924 29,173 27,928 30,056 Total Available for Fixed Charges $96,689 $95,508 $88,729 $87,598* $76,831 Fixed Charges (c) $35,132 $30,818 $30,051 $28,799 $30,560 Ratio of Earnings to Fixed Charges 2.75x 3.10x 2.95x 3.04x* 2.51x * Before cumulative effect of accounting change of $5,521 (net of income taxes). (a) Represents portion (33 1/3%) of rents which is estimated to approximately constitute the return to the lessors on their investment in leased premises. (b) Represents interest and amortization of debt discount and expense on all indebtedness and excludes amortization of gains or losses on reacquired debt which, under the Uniform System of Accounts, is classified as a reduction of, or increase in, interest expense in the Consolidated Statements of Income. Also includes carrying costs associated with natural gas available under a repurchase agreement with Frontier Gas Storage Company as more fully described in Notes to Consolidated Financial Statements. (c) Represents rents and interest, both as defined above. EX-13 6 ANNUAL REPORT 1996 FINANCIAL REPORT REPORT OF MANAGEMENT The management of MDU Resource Group, Inc. is responsible for the preparation, integrity and objectivity of the financial information contained in the consolidated financial statements and elsewhere in this Annual Report. The financial statements have been prepared in conformity with generally accepted accounting principles as applied to the company's regulated and non-regulated businesses and necessarily include some amounts that are based on informed judgments and estimates of management. To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls designed to provide assurance, on a cost-effective basis, that transactions are carried out in accordance with management's authorizations and that assets are safeguarded against loss from unauthorized use or disposition. The system includes an organizational structure which provides an appropriate segregation of responsibilities, careful selection and training of personnel, written policies and procedures and periodic reviews by the Internal Audit Department. In addition, the company has a policy which requires all employees to acknowledge their responsibility for ethical conduct. Management believes that these measures provide for a system that is effective and reasonably assures that all transactions are properly recorded for the preparation of financial statements. Management modifies and improves its system of internal accounting controls in response to changes in business conditions. The company's Internal Audit Department is charged with the responsibility for determining compliance with company procedures. The Board of Directors, through its audit committee which is comprised entirely of outside directors, oversees management's responsibilities for financial reporting. The audit committee meets regularly with management, the internal auditors and Arthur Andersen LLP, independent public accountants, to discuss auditing and financial matters and to assure that each is carrying out its responsibilities. The internal auditors and Arthur Andersen LLP have full and free access to the audit committee, without management present, to discuss auditing, internal accounting control and financial reporting matters. Arthur Andersen LLP is engaged to express an opinion on the financial statements. Their audit is conducted in accordance with generally accepted auditing standards and includes examining, on a test basis, supporting evidence, assessing the company's accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation to the extent necessary to allow them to report on the fairness, in all material respects, of the financial condition and operating results of the company. CONSOLIDATED STATEMENTS OF INCOME MDU RESOURCES GROUP, INC. Years ended December 31, 1996 1995 1994 (In thousands, except per share amounts) Operating Revenues Electric $138,761 $134,609 $133,953 Natural gas 175,408 167,787 160,970 Construction materials and mining 132,222 113,066 116,646 Oil and natural gas production 68,310 48,784 37,959 514,701 464,246 449,528 Operating Expenses Fuel and purchased power 43,983 41,769 43,203 Purchased natural gas sold 48,886 53,351 52,893 Operation and maintenance 225,682 202,327 203,269 Depreciation, depletion and amortization 62,651 54,825 48,113 Taxes, other than income 21,974 21,398 23,875 403,176 373,670 371,353 Operating Income Electric 29,476 29,898 27,596 Natural gas distribution 11,504 6,917 3,948 Natural gas transmission 30,231 25,427 21,281 Construction materials and mining 16,062 14,463 16,593 Oil and natural gas production 24,252 13,871 8,757 111,525 90,576 78,175 Other income -- net 5,617 4,789 10,480 Interest expense 28,832 24,690 25,350 Costs on natural gas repurchase commitment (Note 3) 26,753 5,985 4,627 Income before income taxes 61,557 64,690 58,678 Income taxes 16,087 23,057 18,833 Net income 45,470 41,633 39,845 Dividends on preferred stocks 787 792 797 Earnings on common stock $ 44,683 $ 40,841 $ 39,048 Earnings per common share $ 1.57 $ 1.43 $ 1.37 Dividends per common share $ 1.1000 $ 1.0782 $ 1.0533 Average common shares outstanding 28,477 28,477 28,477 The accompanying notes are an integral part of these consolidated statements. CONSOLIDATED BALANCE SHEETS MDU RESOURCES GROUP, INC. December 31, 1996 1995 1994 (In thousands) ASSETS Property, Plant and Equipment Electric $ 546,477 $ 535,016 $ 514,152 Natural gas distribution 164,843 161,080 157,174 Natural gas transmission 273,775 271,773 263,971 Construction materials and mining 173,663 151,751 147,284 Oil and natural gas production 211,555 167,542 151,532 1,370,313 1,287,162 1,234,113 Less accumulated depreciation, depletion and amortization 617,724 570,855 541,842 752,589 716,307 692,271 Current Assets Cash and cash equivalents 47,799 33,398 37,190 Receivables 73,187 61,961 55,409 Inventories 27,361 23,949 27,090 Deferred income taxes 26,011 31,663 26,694 Prepayments and other current assets 17,300 11,261 12,287 191,658 162,232 158,670 Natural gas available under repurchase commitment (Note 3) 37,233 70,750 70,913 Investments (Note 16) 53,501 46,188 16,914 Deferred charges and other assets 54,192 61,002 65,950 $1,089,173 $1,056,479 $1,004,718 CAPITALIZATION AND LIABILITIES Capitalization (See Separate Statements) Common stockholders' investment $ 350,674 $ 337,317 $ 327,183 Preferred stocks 16,800 16,900 17,000 Long-term debt 280,666 237,352 217,693 648,140 591,569 561,876 Commitments and contingencies (Notes 2,3,4,13 and 15) --- --- --- Current Liabilities Short-term borrowings 3,950 600 680 Accounts payable 31,580 22,261 20,222 Taxes payable 8,683 13,566 8,817 Other accrued liabilities, including reserved revenues 100,938 100,779 88,516 Dividends payable 8,099 7,958 7,793 Long-term debt and preferred stock due within one year 11,854 17,087 20,450 165,104 162,251 146,478 Natural gas repurchase commitment (Note 3) 66,294 88,200 88,404 Deferred credits: Deferred income taxes 116,208 118,459 114,341 Other 93,427 96,000 93,619 209,635 214,459 207,960 $1,089,173 $1,056,479 $1,004,718 The accompanying notes are an integral part of these consolidated statements. CONSOLIDATED STATEMENTS OF CAPITALIZATION MDU RESOURCES GROUP, INC. December 31, 1996 1995 1994 (In thousands) Common Stockholders' Investment Common stock (Note 9): Authorized -- 75,000,000 shares, $3.33 par value Outstanding -- 28,476,981 shares in 1996 and 1995, and 18,984,654 shares in 1994 $ 94,828 $ 94,828 $ 63,219 Other paid in capital 64,305 64,305 95,914 Retained earnings (Note 10) 191,541 178,184 168,050 Total common stockholders' investment 350,674 337,317 327,183 Preferred Stocks (Note 11) Authorized: Preferred -- 500,000 shares, cumulative, par value $100, issuable in series Preferred stock A -- 1,000,000 shares, cumulative, without par value, issuable in series (none outstanding) Preference -- 500,000 shares, cumulative, without par value, issuable in series (none outstanding) Outstanding: Subject to mandatory redemption requirements -- Preferred -- 5.10% Series -- 19,000 shares in 1996 (20,000 in 1995 and 21,000 in 1994) 1,900 2,000 2,100 Other preferred stock -- 4.50% Series -- 100,000 shares 10,000 10,000 10,000 4.70% Series -- 50,000 shares 5,000 5,000 5,000 15,000 15,000 15,000 Total preferred stocks 16,900 17,000 17,100 Less current maturities and sinking fund requirements 100 100 100 Net preferred stocks 16,800 16,900 17,000 Long-term Debt (Note 12) Total long-term debt 292,420 254,339 238,043 Less current maturities and sinking fund requirements 11,754 16,987 20,350 Net long-term debt 280,666 237,352 217,693 Total capitalization $648,140 $591,569 $561,876 The accompanying notes are an integral part of these consolidated statements. CONSOLIDATED STATEMENTS OF CASH FLOWS MDU RESOURCES GROUP, INC. Years ended December 31, 1996 1995 1994 (In thousands) Operating Activities Net income $ 45,470 $ 41,633 $ 39,845 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 62,651 54,825 48,113 Deferred income taxes and investment tax credit -- net 4,551 7,631 3,409 Recovery of deferred natural gas contract litigation settlement costs, net of income taxes 6,580 7,177 7,866 Write-down of natural gas available under repurchase commitment, net of income taxes (Note 3) 11,364 --- --- Changes in current assets and liabilities: Receivables (9,346) (6,552) 12,144 Inventories (1,218) 3,141 (6,799) Other current assets 4,185 (3,943) 7,524 Accounts payable 7,584 2,039 (4,745) Other current liabilities (22,434) 17,177 (19,249) Other noncurrent changes (3,149) (1,023) 6,133 Net cash provided by operating activities 106,238 122,105 94,241 Financing Activities Net change in short-term borrowings 3,350 (80) (8,860) Issuance of long-term debt 81,300 36,710 26,750 Repayment of long-term debt (43,262) (20,433) (35,700) Retirement of preferred stocks (100) (100) (100) Retirement of natural gas repurchase commitment (4,157) (204) (10,121) Dividends paid (32,113) (31,499) (30,793) Net cash provided by (used in) financing activities 5,018 (15,606) (58,824) Investing Activities Capital expenditures including acquisitions of businesses: Electric (18,674) (19,689) (14,188) Natural gas distribution (6,255) (8,878) (19,033) Natural gas transmission (10,127) (9,688) (6,147) Construction materials and mining (25,063) (36,810) (3,597) Oil and natural gas production (51,821) (39,917) (38,595) (111,940) (114,982) (81,560) Net proceeds from sale or disposition of property 11,803 2,802 3,572 Net capital expenditures (100,137) (112,180) (77,988) Sale of natural gas available under repurchase commitment 10,595 163 8,118 Investments (7,313) 1,726 (56) Net cash used in investing activities (96,855) (110,291) (69,926) Increase (decrease) in cash and cash equivalents 14,401 (3,792) (34,509) Cash and cash equivalents -- beginning of year 33,398 37,190 71,699 Cash and cash equivalents -- end of year $ 47,799 $ 33,398 $ 37,190 The accompanying notes are an integral part of these consolidated statements. NOTE 1 Statement of Principal Accounting Policies Basis of Presentation The consolidated financial statements of MDU Resources Group, Inc. (the "company") include the accounts of two regulated businesses -- retail and wholesale sales of electricity and retail sales and/or transportation of natural gas and propane, and natural gas transmission and storage -- and two non-regulated businesses -- construction materials and mining operations, and oil and natural gas production. The statements also include the ownership interests in the assets, liabilities and expenses of two jointly owned electric generating stations. The company's regulated businesses are subject to various state and federal agency regulation. The accounting policies followed by these businesses are generally subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the company's non-regulated businesses. The company's regulated businesses account for certain income and expense items under the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Regulation" (SFAS No. 71). SFAS No. 71 allows these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively, based on the expected regulatory treatment in future rates. The expected recovery or flowback of these deferred items are generally based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistently with the regulatory treatment established by the FERC and the applicable state public service commissions. See Note 6 for more information regarding the nature and amounts of these regulatory deferrals. In accordance with the provisions of SFAS No. 71, intercompany coal sales, which are made at prices approximately the same as those charged to others, and the related utility fuel purchases are not eliminated. All other significant intercompany balances and transactions have been eliminated. Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost when first placed in service. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost and cost of removal, less salvage, is charged to accumulated depreciation. With respect to the retirement or disposal of all other assets, except for oil and natural gas production properties as described below, the resulting gains or losses are recognized as a component of income. The company is permitted to capitalize an allowance for funds used during construction (AFUDC) on regulated construction projects and to include such amounts in rate base when the related facilities are placed in service. In addition, the company capitalizes interest, when applicable, on certain construction projects associated with its other operations. The amounts of AFUDC and interest capitalized were not material in 1996, 1995 and 1994. Property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets, except for oil and natural gas production properties as described below. Investments Investments consist principally of the company's partnership investment in Hawaiian Cement. The company accounts for its partnership investment in Hawaiian Cement by the equity method. See Note 16 for more information on this partnership investment. Oil and Natural Gas The company uses the full-cost method of accounting for its oil and natural gas production activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized and amortized on the units of production method based on total proved reserves. Cost centers for amortization purposes are determined on a country-by-country basis. Capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net revenues of proved reserves and the lower of cost or fair value of unproved properties. Any conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of the properties with no gain or loss realized. Natural Gas in Underground Storage and Available Under Repurchase Commitment Natural gas in underground storage is carried at cost using the last-in, first-out (LIFO) method. That portion of the cost of natural gas in underground storage expected to be used within one year is included in inventories. Natural gas available under a repurchase commitment with Frontier Gas Storage Company (Frontier) is carried at Frontier's cost of purchased natural gas, less an allowance to reflect changed market conditions. See Note 3 for more information on a write-down of the natural gas available under the repurchase commitment with Frontier which occurred in 1996. Inventories Inventories, other than natural gas in underground storage, consist primarily of materials and supplies and inventory held for resale. These inventories are stated at the lower of average cost or market. Revenue Recognition The company recognizes utility revenue each month based on the services provided to all utility customers during the month. In addition, the company recognizes revenue for its construction business on the percentage of completion method. Natural Gas Costs Recoverable Through Rate Adjustments Under the terms of certain orders of the applicable state public service commissions, the company is deferring natural gas commodity, transportation and storage costs which are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments within 24 months from the time such costs are paid. Income Taxes The company provides deferred federal and state income taxes on all temporary differences. Excess deferred income tax balances associated with Montana-Dakota's and Williston Basin's rate-regulated activities resulting from the company's adoption of SFAS No. 109, "Accounting for Income Taxes," have been recorded as a regulatory liability and are included in "Other deferred credits" in the company's Consolidated Balance Sheets. This regulatory liability is expected to be reflected as a reduction in future rates charged customers in accordance with applicable regulatory procedures. The company uses the deferral method of accounting for investment tax credits and amortizes the credits on electric and natural gas distribution plant over various periods which conform to the ratemaking treatment prescribed by the applicable state public service commissions. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires the company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, environmental and other loss contingencies, unbilled revenues and actuarially determined benefit costs. As better information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Cash Flow Information Cash expenditures for interest and income taxes were as follows: Years ended December 31, 1996 1995 1994 (In thousands) Interest, net of amount capitalized $25,449 $24,436 $22,775 Income taxes $28,163 $18,330 $13,539 The company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Reclassifications Certain reclassifications have been made in the financial statements for 1995 and 1994 to conform to the 1996 presentation. Such reclassifications had no effect on net income or common stockholders' investment as previously reported. New Accounting Standard In October 1996, the American Institute of Certified Public Accountants issued Statement of Position 96-1, "Environmental Remediation Liabilities" (SOP 96-1). SOP 96-1 provides authoritative guidance for the recognition, measurement, display and disclosure of environmental remediation liabilities in financial statements. The company will adopt SOP 96-1 on January 1, 1997, and the adoption is not expected to have a material effect on the company's financial position or results of operations. NOTE 2 Regulatory Matters and Revenues Subject to Refund General Rate Proceedings Williston Basin has pending with the FERC a general natural gas rate change application implemented in 1992. In July 1995, the FERC issued an order relating to Williston Basin's rate change application. In August 1995, Williston Basin filed, under protest, tariff sheets in compliance with the FERC's order, with rates which went into effect on September 1, 1995. Williston Basin requested rehearing of certain issues addressed in the order. On July 19, 1996, the FERC issued an order granting in part and denying in part Williston Basin's rehearing request. A hearing was held on August 29, 1996, and this matter is currently pending before the FERC. In addition, Williston Basin has appealed certain issues contained in the FERC's orders to the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit Court). Williston Basin anticipates filing briefs with the D.C. Circuit Court on February 3, 1997, related to its appeal of orders which had been received from the FERC beginning in May 1993, regarding the appropriate selling price of certain natural gas in underground storage which was determined to be excess upon Williston Basin's implementation of Order 636. The FERC ordered that the gas be offered for sale to Williston Basin's customers at its original cost. Williston Basin requested rehearing of this matter on the grounds that the FERC's order constituted a confiscation of its assets, which request was subsequently denied by the FERC. Williston Basin believes that it should be allowed to sell this natural gas at its fair value and retain any profits resulting from such sales since its ratepayers had never paid for the natural gas. Oral arguments on this matter before the D.C. Circuit Court are scheduled for May 9, 1997. Reserves have been provided for a portion of the revenues that have been collected subject to refund with respect to pending regulatory proceedings and for the recovery of certain producer settlement buy- out/buy-down costs to reflect future resolution of certain issues with the FERC. Williston Basin believes that such reserves are adequate based on its assessment of the ultimate outcome of the various proceedings. NOTE 3 Natural Gas Repurchase Commitment The company has offered for sale since 1984 the inventoried natural gas owned by Frontier, a special purpose, non-affiliated corporation. Through an agreement, Williston Basin is obligated to repurchase all of the natural gas at Frontier's original cost and reimburse Frontier for all of its financing and general administrative costs. Frontier has financed the purchase of the natural gas under a term loan agreement with several banks. At December 31, 1996, borrowings totalled $84.0 million at a weighted average interest rate of 6.13 percent of which $66.3 million is reflected on the company's Consolidated Balance Sheets under "Natural gas repurchase commitment" and $17.7 million is included in "Other accrued liabilities" and relates to current amounts owed as a result of recent sales of a portion of this natural gas. The term loan agreement will terminate on October 2, 1999, subject to an option to renew this agreement upon the lenders' consent for up to five years, unless terminated earlier by the occurrence of certain events. The FERC has issued orders that have held that storage costs should be allocated to this gas, prospectively beginning May 1992, as opposed to being included in rates applicable to Williston Basin's customers. These storage costs, as initially allocated to the Frontier gas, approximated $2.1 million annually, for which Williston Basin has provided reserves. Williston Basin appealed these orders to the D.C. Circuit Court. On December 26, 1996, the D.C. Circuit Court issued its order ruling that the FERC's actions in allocating costs to the Frontier gas were appropriate. Williston Basin is awaiting a final order from the FERC. Beginning in October 1992, as a result of prevailing natural gas prices, Williston Basin began to sell and transport a portion of the natural gas held under the repurchase commitment. Through the second quarter of 1996, 17.8 MMdk of this natural gas had been sold. However, in the third quarter of 1996, Williston Basin, based on a number of factors including differences in regional natural gas prices and natural gas sales occurring at that time, wrote down the remaining 43.0 MMdk of this gas to its then current market value. The value of this gas was determined using the sum of discounted cash flows of expected future sales occurring at then current regional natural gas prices as adjusted for anticipated future price increases. This resulted in a write-down aggregating $18.6 million ($11.4 million after tax). In addition, Williston Basin wrote off certain other costs related to this natural gas of approximately $2.5 million ($1.5 million after tax). The amounts related to this write-down are included in "Costs on natural gas repurchase commitment" in the Consolidated Statements of Income. The recognition of the then current market value of this natural gas facilitated the sale by Williston Basin of 10.5 MMdk from the date of this write-down through December 31, 1996, and should allow Williston Basin to market the remaining 32.5 MMdk on a sustained basis enabling Williston Basin to liquidate this asset over approximately the next five years. NOTE 4 Commitments and Contingencies Pending Litigation In November 1993, the estate of W.A. Moncrief (Moncrief), a producer from whom Williston Basin purchased a portion of its natural gas supply, filed suit in Federal District Court for the District of Wyoming (Federal District Court) against Williston Basin and the company disputing certain price and volume issues under the contract. Through the course of this action Moncrief submitted damage calculations which totalled approximately $19 million or, under its alternative pricing theory, approximately $39 million. On August 16, 1996, the Federal District Court issued its decision finding that Moncrief is entitled to damages for the difference between the price Moncrief would have received under the geographic favored-nations price clause of the contract for the period from August 13, 1993, through July 7, 1996, and the actual price received for the gas. The favored-nations price is the highest price paid from time to time under contracts in the same geographic region for natural gas of similar quantity and quality. The Federal District Court reopened the record until October 15, 1996, to receive additional briefs and exhibits on this issue. On October 15, 1996, Moncrief submitted its brief claiming damages ranging as high as $22 million under the geographic favored-nations price theory. Williston Basin, in its brief, contended that Moncrief waived its claim for a favored-nations price under an agreement with Williston Basin, and Moncrief's damage claims were calculated utilizing non-comparable contracts. Williston Basin's exhibits show Moncrief's damages should be limited to approximately $800,000 under the geographic favored-nations price theory. A hearing on all pending matters is currently scheduled for April 3, 1997. Williston Basin plans to file for recovery from ratepayers of amounts which may be ultimately due to Moncrief, if any. In December 1993, Apache Corporation (Apache) and Snyder Oil Corporation (Snyder) filed suit in North Dakota District Court, Northwest Judicial District, against Williston Basin and the company. Apache and Snyder are oil and natural gas producers who had processing agreements with Koch Hydrocarbon Company (Koch). Williston Basin and the company had a natural gas purchase contract with Koch. Apache and Snyder have alleged they are entitled to damages for the breach of Williston Basin's and the company's contract with Koch. Williston Basin and the company believe that if Apache and Snyder have any legal claims, such claims are with Koch, not with Williston Basin or the company. Williston Basin, the company and Koch have settled their disputes. Apache and Snyder have recently provided alleged damages under differing theories ranging up to $8.2 million without interest. A motion to intervene in the case by several other producers, all of whom had contracts with Koch but not with Williston Basin, was denied on December 13, 1996. Trial on this matter is scheduled for September 8, 1997. The claims of Apache and Snyder, in Williston Basin's opinion, are without merit and overstated. If any amounts are ultimately found to be due Apache and Snyder, Williston Basin plans to file for recovery from ratepayers. On July 18, 1996, Jack J. Grynberg (Grynberg) filed suit in United States District Court for the District of Columbia against Williston Basin and over 70 other natural gas pipeline companies. Grynberg, acting on behalf of the United States under the False Claims Act, is alleging improper measurement of the heating content or volume of natural gas purchased by the defendants resulting in the underpayment of royalties to the United States. The United States government, particularly officials from the Departments of Justice and Interior, reviewed the complaint and the evidence presented by Grynberg and declined to intervene in the action, permitting Grynberg to proceed on his own. Williston Basin believes Grynberg's claims are without merit and intends to vigorously contest this suit. In November 1995, a suit was filed in District Court, County of Burleigh, State of North Dakota (State District Court) by Minnkota Power Cooperative, Inc., Otter Tail Power Company, Northwestern Public Service Company and Northern Municipal Power Agency (Co-owners), the owners of an aggregate 75 percent interest in the Coyote electrical generating station (Coyote Station), against the company (an owner of a 25 percent interest in the Coyote Station) and Knife River. In its complaint, the Co-owners alleged a breach of contract against Knife River of the long-term coal supply agreement (Agreement) between the owners of the Coyote Station and Knife River. The Co-owners have requested a determination by the State District Court of the pricing mechanism to be applied to the Agreement and have further requested damages during the term of such alleged breach on the difference between the prices charged by Knife River and the prices as may ultimately be determined by the State District Court. The Co-owners also alleged a breach of fiduciary duties by the company as operating agent of the Coyote Station, asserting essentially that the company was unable to cause Knife River to reduce its coal price sufficiently under the Agreement, and are seeking damages in an unspecified amount. On January 8, 1996, the company and Knife River filed separate motions with the State District Court to dismiss or stay pending arbitration. On May 6, 1996, the State District Court granted the company's and Knife River's motions and stayed the suit filed by the Co-owners pending arbitration, as provided for in the Agreement. On September 12, 1996, the Co-owners notified the company and Knife River of their demand for arbitration of the pricing dispute that had arisen under the Agreement. The demand for arbitration, filed with the American Arbitration Association (AAA), did not make any direct claim against the company in its capacity as operator of the Coyote Station. The Co-owners requested that the arbitrators make a determination that the pricing dispute is not a proper subject for arbitration. In the alternative, the Co-owners requested the arbitrators to make a determination that the prices charged by Knife River were excessive and that the Co-owners should be awarded damages based upon the difference between the prices that Knife River charged and a "fair and equitable" price, approximately $50 million or more. Upon application by the company and Knife River, the AAA administratively determined that the company was not a proper party defendant to the arbitration, and the arbitration is proceeding against Knife River. Although unable to predict the outcome of the arbitration, Knife River and the company believe that the Co-owners claims are without merit and intend to vigorously defend the prices charged pursuant to the Agreement. For a description of litigation filed by Unitek Environmental Services, Inc. against Hawaiian Cement, see Environmental Matters. The company is also involved in other legal actions in the ordinary course of its business. Although the outcomes of any such legal actions cannot be predicted, management believes that there is no pending legal proceeding against or involving the company, except those discussed above, for which the outcome is likely to have a material adverse effect upon the company's financial position or results of operations. Environmental Matters Montana-Dakota and Williston Basin discovered polychlorinated biphenyls (PCBs) in portions of their natural gas systems and informed the United States Environmental Protection Agency (EPA) in January 1991. Montana-Dakota and Williston Basin believe the PCBs entered the system from a valve sealant. In January 1994, Montana- Dakota, Williston Basin and Rockwell International Corporation (Rockwell), manufacturer of the valve sealant, reached an agreement under which Rockwell has and will continue to reimburse Montana-Dakota and Williston Basin for a portion of certain remediation costs. On the basis of findings to date, Montana-Dakota and Williston Basin estimate future environmental assessment and remediation costs will aggregate $3 million to $15 million. Based on such estimated cost, the expected recovery from Rockwell and the ability of Montana-Dakota and Williston Basin to recover their portions of such costs from ratepayers, Montana-Dakota and Williston Basin believe that the ultimate costs related to these matters will not be material to each of their respective financial positions or results of operations. In September 1995, Unitek Environmental Services, Inc. and Unitek Solvent Services, Inc. (Unitek) filed a complaint against Hawaiian Cement in the United States District Court for the District of Hawaii (District Court) alleging that dust emissions from Hawaiian Cement's cement manufacturing plant at Kapolei, Hawaii (Plant) violated the Hawaii State Implementation Plan (SIP) of the U.S. Clean Air Act (Clean Air Act), constituted a continual nuisance and trespass on the plaintiff's property, and that Hawaiian Cement's conduct warranted the payment of punitive damages. Hawaiian Cement is a Hawaiian general partnership whose general partners (with joint and several liability) are Knife River Hawaii, Inc., an indirect wholly owned subsidiary of the company, and Adelaide Brighton Cement (Hawaii), Inc. Unitek is seeking civil penalties under the Clean Air Act (as described below), and had sought damages for various claims (as described above) of up to $20 million in the aggregate. On August 7, 1996, the District Court issued an order granting Plaintiffs' motion for partial summary judgment relating to the Clean Air Act, indicating that it would issue an injunction shortly. The issue of civil penalties under the Clean Air Act was reserved for further hearing at a later date, and Unitek's claims for damages were not addressed by the District Court at such time. On September 16, 1996, Unitek and Hawaiian Cement reached a settlement which resolved all claims relating to the $20 million in damages that Unitek had previously sought. However, the settlement did not resolve the matter regarding the civil penalties sought by Unitek relating to the alleged violations by Hawaiian Cement of the Clean Air Act nor did it affect the EPA's Notice of Violation (NOV) as discussed below. Based on a joint petition filed by Unitek and Hawaiian Cement, the District Court stayed the proceeding and the issuance of an injunction while the parties continue to negotiate the remaining Clean Air Act claims. On May 7, 1996, the EPA issued a NOV to Hawaiian Cement. The NOV states that dust emissions from the Plant violated the SIP. Under the Clean Air Act, the EPA has the authority to issue an order requiring compliance with the SIP, issue an administrative order requiring the payment of penalties of up to $25,000 per day per violation (not to exceed $200,000), or bring a civil action for penalties of not more than $25,000 per day per violation and/or bring a civil action for injunctive relief. It is also possible that the EPA could elect to join the suit filed by Unitek. Depending upon the specific actions that may ultimately be taken by either the EPA or the District Court, Hawaiian Cement is likely to have to modify its operations at its cement manufacturing facility. Hawaiian Cement has met with the EPA and settlement discussions are currently ongoing. Although no assurance can be provided, the company does not believe that the total cost of any modifications to the facility, the level of civil penalties which may ultimately be assessed or settlement costs, will have a material effect on the company's results of operations. Electric Purchased Power Commitments Montana-Dakota has contracted to purchase through October 31, 2006, up to 66,400 kW of participation power from Basin Electric Power Cooperative. In addition, Montana-Dakota under a power supply contract through December 31, 2006, is purchasing up to 55,000 kW of capacity from Black Hills Power and Light Company. NOTE 5 Natural Gas in Underground Storage Natural gas in underground storage included in natural gas transmission and natural gas distribution property, plant and equipment amounted to approximately $42.3 million at December 31, 1996, $42.1 million at December 31, 1995, and $45.2 million at December 31, 1994. In addition, $7.2 million, $6.6 million and $6.9 million at December 31, 1996, 1995 and 1994, respectively, of natural gas in underground storage is included in inventories. NOTE 6 Regulatory Assets and Liabilities The following table summarizes the individual components of unamortized regulatory assets and liabilities included in the accompanying Consolidated Balance Sheets as of December 31: 1996 1995 1994 (In thousands) Regulatory assets: Natural gas contract settlement and restructuring costs $ 4,960 $ 15,275 $ 24,069 Long-term debt refinancing costs 13,520 11,082 12,228 Postretirement benefit costs 3,849 4,833 4,551 Plant costs 3,341 3,509 3,678 Other 7,890 7,091 4,664 Total regulatory assets 33,560 41,790 49,190 Regulatory liabilities: Reserves for regulatory matters 59,277 58,277 49,427 Natural gas costs refundable through rate adjustments 1,499 21,192 14,878 Taxes refundable to customers 12,868 12,531 12,229 Plant decommissioning costs 5,301 4,777 4,290 Other 2,433 7,205 9,883 Total regulatory liabilities 81,378 103,982 90,707 Net regulatory position $(47,818) $(62,192) $(41,517) As of December 31, 1996, substantially all of the company's regulatory assets are being reflected in rates charged to customers and are being recovered over the next 1 to 20 years. If for any reason, the company's regulated businesses cease to meet the criteria for application of SFAS No. 71 for all or part of their operations, the regulatory assets and liabilities relating to those portions ceasing to meet such criteria would be removed from the balance sheet and included in the statement of income as an extraordinary item in the period in which the discontinuance of SFAS No. 71 occurs. NOTE 7 Financial Instruments Derivatives The company, in connection with the operations of Montana-Dakota, Williston Basin and Fidelity Oil, has entered into certain price swap and collar agreements (hedge agreements) to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas. These hedge agreements are not held for trading purposes. The hedge agreements call for the company to receive monthly payments from or make payments to counterparties based upon the difference between a fixed and a variable price as specified by the hedge agreements. The variable price is either an oil price quoted on the New York Mercantile Exchange (NYMEX) or a quoted natural gas price on the NYMEX or Colorado Interstate Gas Index. The company believes that there is a high degree of correlation because the timing of purchases and production and the hedge agreements are closely matched, and hedge prices are established in the areas of the company's operations. Amounts payable or receivable on hedge agreements are matched and reported in operating revenues on the Consolidated Statements of Income as a component of the related commodity transaction at the time of settlement with the counterparty. The amounts payable or receivable are offset by corresponding increases and decreases in the value of the underlying commodity transactions. Williston Basin and Knife River have entered into interest rate swap agreements to manage a portion of their interest rate exposure on a natural gas repurchase commitment and long-term debt, respectively. These interest rate swap agreements are not held for trading purposes. The interest rate swap agreements call for the company to receive quarterly payments from or make payments to counterparties based upon the difference between fixed and variable rates as specified by the interest rate swap agreements. The variable prices are based on the three-month floating London Interbank Offered Rate. Settlement amounts payable or receivable under these interest rate swap agreements are recorded in "Interest expense" for Knife River and "Costs on natural gas repurchase commitment" for Williston Basin on the Consolidated Statements of Income in the accounting period they are incurred. The amounts payable or receivable are offset by interest on the related debt instruments. The company's policy prohibits the use of derivative instruments for trading purposes and the company has procedures in place to monitor their use. The company is exposed to credit-related losses in the event of nonperformance by counterparties to these financial instruments, but does not expect any counterparties to fail to meet their obligations given their existing credit ratings. The following table summarizes the company's hedging activity for 1996, 1995 and 1994: 1996 1995 1994 (Notional amounts in thousands) Oil swap/collar agreements:* Range of fixed prices per barrel $18.74-$19.07 $17.75-$20.75 $17.00-$21.05 Notional amount (in barrels) 635 260 242 Natural gas swap/collar agreements:* Range of fixed prices per MMBtu $1.40-$2.05 $1.70-$1.85 $1.85-$2.32 Notional amount (in MMBtu's) 5,331 644 3,130 Natural gas collar agreement:** Fixed price per MMBtu $1.22-$1.52 $1.22-$1.52 --- Notional amount (in MMBtu's) 910 2,750 --- Interest rate swap agreements:** Range of fixed interest rates 5.50%-6.50% 5.97% --- Notional amount (in dollars) $30,000 $20,000 --- * Receive fixed -- pay variable ** Receive variable -- pay fixed The following table summarizes swap agreements outstanding at December 31, 1996 (notional amounts in thousands): Range of Notional Fixed Prices Amount Year (Per barrel) (In barrels) Oil swap agreements* 1997 $19.77-$21.36 730 Range of Notional Fixed Prices Amount Year (Per MMBtu) (In MMBtu's) Natural gas swap agreements* 1997 $1.30-$2.25 7,737 Notional Range of Fixed Amount Year Interest Rates (In dollars) Interest rate swap agreements:** 1997 5.50%-6.50% $30,000 1998 5.50%-6.50% $10,000 * Receive fixed -- pay variable ** Receive variable -- pay fixed The fair value of these derivative financial instruments reflects the estimated amounts that the company would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current favorable or unfavorable position on open contracts. The favorable or unfavorable position is currently not recorded on the company's financial statements. Favorable and unfavorable positions related to oil and natural gas hedge agreements will be offset by corresponding increases and decreases in the value of the underlying commodity transactions. Favorable and unfavorable positions on interest rate swap agreements will be offset by interest on the related debt instruments. The company's net unfavorable position on all swap and collar agreements outstanding at December 31, 1996, was $4.2 million. Fair Value of Other Financial Instruments The estimated fair value of the company's long-term debt and preferred stocks are based on quoted market prices of the same or similar issues. The estimated fair value of the company's long-term debt and preferred stocks at December 31 are as follows: 1996 1995 1994 Carrying Fair Carrying Fair Carrying Fair Amount Value Amount Value Amount Value (In thousands) Long-term debt $292,420 $298,592 $254,339 $ 274,320 $ 238,043 $ 233,196 Preferred stocks $ 16,900 $ 10,762 $ 17,000 $ 10,500 $ 17,100 $ 10,486 The fair value of other financial instruments for which estimated fair values have not been presented is not materially different than the related book value. NOTE 8 Short-term Borrowings The company and its subsidiaries had unsecured lines of credit from several banks totalling $91.4 million at December 31, 1996. These line of credit agreements provide for bank borrowings against the lines and/or support for commercial paper issues. The agreements provide for commitment fees at varying rates. Amounts outstanding under the lines of credit were $4.0 million at December 31, 1996, $600,000 at December 31, 1995, and $680,000 at December 31, 1994. The weighted average interest rate for borrowings outstanding at December 31, 1996, 1995 and 1994, was 7.25 percent, 8.50 percent and 8.50 percent, respectively. The unused portions of the lines of credit are subject to withdrawal based on the occurrence of certain events. NOTE 9 Common Stock At the Annual Meeting of Stockholders held in April 1994, the company's common stockholders approved an amendment to the Certificate of Incorporation increasing the authorized number of common shares from 50 million shares to 75 million shares and reducing the par value of the common stock from $5.00 per share to $3.33 per share. In August 1995, the company's Board of Directors approved a three-for- two common stock split to be effected in the form of a 50 percent common stock dividend. The additional shares of common stock were distributed on October 13, 1995, to common stockholders of record on September 27, 1995. Common stock information appearing in the accompanying consolidated financial statements and notes thereto has been restated to give retroactive effect to the stock split, except for shares outstanding in 1994 as set forth in the table below. Changes in common stock and other paid in capital during the years ended December 31, 1996, 1995 and 1994 are summarized below: Shares Par Other Paid Outstanding Value In Capital (In thousands) Balance at December 31, 1994 18,984,654 $63,219 $ 95,914 Three-for-two common stock split 9,492,327 31,609 (31,609) Balance at December 31, 1995 and 1996 28,476,981 $94,828 $ 64,305 The company's Automatic Dividend Reinvestment and Stock Purchase Plan (DRIP) provides participants in the DRIP the opportunity to invest all or a portion of their cash dividends in shares of the company's common stock and/or to make optional cash payments of up to $5,000 per month for the same purpose. Holders of all classes of the company's capital stock and other investors who are domiciled in the states of North Dakota, South Dakota, Montana or Wyoming, are eligible to participate in the DRIP. The company's Tax Deferred Compensation Savings Plans (K-Plans) pursuant to Section 401(k) of the Internal Revenue Code are funded with the company's common stock. Shares held in the K-Plans also participate in the DRIP. Since January 1, 1989, the DRIP and K- Plans have been funded by the purchase of shares of common stock on the open market. However, beginning January 1, 1997, shares of authorized but unissued common stock are being used to fund the DRIP. At December 31, 1996, there were 5,830,345 shares of common stock reserved for issuance under the DRIP and K-Plans. In November 1988, the company's Board of Directors declared, pursuant to a stockholders' rights plan, a dividend of one preference share purchase right (right) on each outstanding share of the company's common stock. Each right becomes exercisable, upon the occurrence of certain events, for one one-hundred and fiftieth of a share of Series A preference stock, without par value, at an exercise price of $33.33 per one one-hundred and fiftieth, subject to certain adjustments. The rights are currently not exercisable and will be exercisable only if a person or group (acquiring person) either acquires ownership of 20 percent or more of the company's common stock or commences a tender or exchange offer that would result in ownership of 30 percent or more. In the event the company is acquired in a merger or other business combination transaction or 50 percent or more of its consolidated assets or earnings power are sold, each right entitles the holder to receive, upon the exercise thereof at the then current exercise price of the right multiplied by the number of one one-hundredths of a Series A preference share for which a right is then exercisable, in accordance with the terms of the Rights Agreement, such number of shares of common stock of the acquiring person having a market value of twice the then current exercise price of the right. The rights, which expire in November 1998, are redeemable in whole, but not in part, for a price of $.01333 per right, at the company's option at any time until any acquiring person has acquired 20 percent or more of the company's common stock. Preference share purchase rights have been appropriately adjusted to reflect the effects of the common stock split discussed above. NOTE 10 Retained Earnings Changes in retained earnings for the years ended December 31, 1996, 1995 and 1994 are as follows: 1996 1995 1994 (In thousands) Balance at beginning of year $178,184 $168,050 $158,998 Net income 45,470 41,633 39,845 223,654 209,683 198,843 Deduct: Dividends declared -- Preferred stocks at required annual rates 787 792 797 Common stock 31,326 30,707 29,996 32,113 31,499 30,793 Balance at end of year $191,541 $178,184 $168,050 NOTE 11 Preferred Stocks The preferred stocks outstanding are subject to redemption, in whole or in part, at the option of the company with certain limitations on 30 days notice on any quarterly dividend date. The company is obligated to make annual sinking fund contributions to retire the 5.10% Series preferred stock. The redemption prices and sinking fund requirements, where applicable, are summarized below: Redemption Sinking Fund Series Price (a) Shares Price (a) Preferred stock: 4.50% $105.00 (b) --- --- 4.70% $102.00 (b) --- --- 5.10% $102.00 1,000 (c) $100.00 (a) Plus accrued dividends. (b) These series are redeemable at the sole discretion of the company. (c) Annually on December 1, if tendered. In the event of a voluntary or involuntary liquidation, all preferred stock series holders are entitled to $100 per share, plus accrued dividends. The aggregate annual sinking fund amount applicable to preferred stock subject to mandatory redemption requirements for each of the five years following December 31, 1996, is $100,000. NOTE 12 Long-term Debt and Indenture Provisions Long-term debt outstanding at December 31 is as follows: 1996 1995 1994 (In thousands) First mortgage bonds and notes: 9 1/8% Series, due May 15, 2006 $ 25,000 $ 50,000 $ 50,000 9 1/8% Series, due October 1, 2016 20,000 20,000 20,000 Pollution Control Refunding Revenue Bonds, Series 1992: Mercer County, North Dakota, 6.65%, due June 1, 2022 15,000 15,000 15,000 Morton County, North Dakota, 6.65%, due June 1, 2022 2,600 2,600 2,600 Richland County, Montana, 6.65%, due June 1, 2022 3,250 3,250 3,250 Secured Medium-Term Notes, Series A: 6.30%, due April 1, 1995 --- --- 10,000 6.95%, due April 1, 1996 --- 10,000 10,000 7.20%, due April 1, 1997 5,000 5,000 5,000 8.25%, due April 1, 2007 30,000 30,000 30,000 8.60%, due April 1, 2012 35,000 35,000 35,000 Total first mortgage bonds and notes 135,850 170,850 180,850 Pollution control lease and note obligation, 6.20%, due March 1, 2004 4,000 4,300 4,600 Senior notes: 7.35%, due July 31, 2002 5,000 5,000 --- 8.43%, due December 31, 2000 15,000 15,000 15,000 7.51%, expires October 9, 2003 3,000 --- --- 7.45%, due May 31, 2006 20,000 --- --- 7.60%, due November 3, 2008 15,000 --- --- Revolving lines of credit: 8.25%, expires December 31, 1998 30,000 21,500 17,000 Other revolving lines of credit at rates ranging from 6.03% to 8.50%, expiring at various dates ranging from October 6, 2001, through April 30, 2002 61,800 27,000 3,000 Term credit facilities: 5.95%, due March 31, 1997 --- 7,500 17,500 7.70%, due December 1, 2003 1,556 1,800 --- Other term credit facilities at rates ranging from 8.00% to 9.00%, due from June 30, 1999, through December 1, 2000 1,308 1,527 250 Other (94) (138) (157) Total long-term debt 292,420 254,339 238,043 Less current maturities and sinking fund requirements 11,754 16,987 20,350 Net long-term debt $280,666 $237,352 $217,693 Under the revolving lines of credit, the company has $120 million available, $91.8 million of which was outstanding at December 31, 1996. The amounts of scheduled long-term debt maturities and sinking fund requirements for the five years following December 31, 1996, aggregate $11.8 million in 1997; $44.5 million in 1998; $15.1 million in 1999; $18.4 million in 2000 and $10.9 million in 2001. Substantially all of the company's electric and natural gas distribution properties, with certain exceptions, are subject to the lien of its Indenture of Mortgage. Under the terms and conditions of such Indenture, the company could have issued approximately $247 million of additional first mortgage bonds at December 31, 1996. Certain of the company's other debt instruments contain restrictive covenants all of which the company is in compliance with at December 31, 1996. NOTE 13 Income Taxes Income tax expense is summarized as follows: 1996 1995 1994 (In thousands) Current: Federal $12,617 $20,259 $11,995 State 3,272 3,801 2,644 Foreign 60 369 210 15,949 24,429 14,849 Deferred: Investment tax credit -- net (1,099) (1,028) (1,137) Income taxes -- Federal 1,139 (564) 4,589 State 120 220 532 Foreign (22) --- --- 138 (1,372) 3,984 Total income tax expense $16,087 $23,057 $18,833 Components of deferred tax assets and deferred tax liabilities recognized in the company's Consolidated Balance Sheets at December 31 are as follows: 1996 1995 1994 (In thousands) Deferred tax assets: Reserves for regulatory matters $ 38,404 $ 36,894 $ 33,076 Natural gas available under repurchase commitment 10,521 6,762 6,778 Accrued pension costs 7,814 7,039 5,646 Deferred investment tax credits 3,160 3,623 4,022 Accrued land reclamation 3,604 4,033 4,256 Natural gas costs refundable through rate adjustments --- 6,125 4,034 Other 13,499 11,321 10,220 Total deferred tax assets 77,002 75,797 68,032 Deferred tax liabilities: Depreciation and basis differences on property, plant and equipment 121,763 119,078 115,966 Basis differences on oil and natural gas producing properties 30,361 28,113 21,049 Natural gas contract settlement and restructuring costs 1,926 5,413 9,327 Long-term debt refinancing costs 4,688 4,524 4,745 Other 8,461 5,465 4,592 Total deferred tax liabilities 167,199 162,593 155,679 Net deferred income tax liability $(90,197) $(86,796) $(87,647) The following table reconciles the change in the net deferred income tax liability to the deferred income tax expense included in the Consolidated Statements of Income: 1996 1995 (In thousands) Net change in deferred income tax liability from the preceding table $ 3,401 $(851) Change in tax effects of income tax-related regulatory assets and liabilities 1,155 507 Deferred taxes associated with acquisitions (3,319) --- Deferred income tax expense for the period $ 1,237 $(344) Total income tax expense differs from the amount computed by applying the statutory federal income tax rate to income before taxes. The reasons for this difference are as follows: 1996 1995 1994 Amount % Amount % Amount % (Dollars in thousands) Computed tax at federal statutory rate $21,545 35.0 $22,642 35.0 $20,537 35.0 Increases (reductions) resulting from: Depletion allowance (1,070) (1.7) (1,346) (2.1) (1,454)(2.5) State income taxes -- net of federal income tax benefit 2,770 4.5 2,492 3.9 2,337 4.0 Investment tax credit amortization (1,099) (1.8) (1,028) (1.6) (1,137)(1.9) Tax reserve adjustment (6,600)(10.7) --- --- --- --- Other items 541 .8 297 .4 (1,450)(2.5) Actual taxes $16,087 26.1 $23,057 35.6 $18,833 32.1 The company's consolidated federal income tax returns were under examination by the Internal Revenue Service (IRS) for the tax years 1983 through 1991. In 1991, the company received a notice of proposed deficiency from the IRS for the tax years 1983 through 1985 which proposed substantial additional income taxes, plus interest. In an alternative position contained in the notice of proposed deficiency, the IRS had claimed a lower level of taxes due, plus interest as well as penalties. In 1992 and 1995, similar notices of proposed deficiency were received for the years 1986 through 1988 and 1989 through 1991, respectively. Although the notices of proposed deficiency encompass a number of separate issues, the principal issue was related to the tax treatment of deductions claimed in connection with certain investments made by Knife River and Fidelity Oil. The company timely filed protests for the 1983 through 1991 tax years contesting the treatment proposed in the notices of proposed deficiency. In April 1996, the company and the IRS reached a settlement for the tax years 1983 through 1988, which should also result in settlement of related issues for the years 1989 through 1991. The company reflected the effect of the settlement in the third quarter of 1996 and, in addition, reversed reserves previously provided which were deemed to be no longer required. NOTE 14 Business Segment Data The company's operations are conducted through five business segments. The electric, natural gas distribution, natural gas transmission, construction materials and mining, and oil and natural gas production businesses are substantially all located within the United States. A description of these segments and their primary operations is presented on the inside front cover. Segment operating information at December 31, 1996, 1995 and 1994, is presented in the Consolidated Statements of Income. Other segment information is presented below: 1996 1995 1994 (In thousands) Depreciation, depletion and amortization: Electric $ 17,053 $ 16,361 $ 15,513 Natural gas distribution 6,880 6,719 6,118 Natural gas transmission 6,748 6,940 6,590 Construction materials and mining 6,974 6,199 6,394 Oil and natural gas production 24,996 18,606 13,498 Total depreciation, depletion and amortization $ 62,651 $ 54,825 $ 48,113 Investment information: Identifiable assets-- Electric (a) $ 313,815 $ 312,559 $ 307,861 Natural gas distribution (a) 120,645 126,452 124,275 Natural gas transmission (a) 276,843 303,219 311,992 Construction materials and mining 171,283 141,505 116,347 Oil and natural gas production 161,647 133,289 106,631 Total identifiable assets 1,044,233 1,017,024 967,106 Corporate assets (b) 44,940 39,455 37,612 Total consolidated assets $1,089,173 $1,056,479 $1,004,718 (a) Includes, in the case of electric and natural gas distribution property, allocations of common utility property. Natural gas stored or available under repurchase commitment, as applicable, is included in natural gas distribution and transmission identifiable assets. (b) Corporate assets consist of assets not directly assignable to a business segment, i.e., cash and cash equivalents, certain accounts receivable and other miscellaneous current and deferred assets. Approximately 4 percent of construction materials and mining revenues in 1996 (4 percent in 1995 and 6 percent in 1994) represent Knife River's direct sales of lignite coal to the company. The company's share of Knife River's 1996 sales for use at the Coyote Station, a generating station jointly owned by the company and other utilities, was approximately 5 percent of construction materials and mining revenues in 1996. In 1995 and 1994, the company's share of Knife River's sales for use at the Coyote Station and the Big Stone Station, another generating station jointly owned by the company and other utilities, was 7 percent and 8 percent, respectively, of construction materials and mining revenues. In April 1996, KRC Holdings, Inc.(KRC Holdings), a wholly owned subsidiary of Knife River, purchased Baldwin Contracting Company, Inc. (Baldwin) of Chico, California. Baldwin is a major supplier of aggregate, asphalt and construction services in the northern Sacramento Valley and adjacent Sierra Nevada Mountains of northern California. Baldwin also provides a variety of construction services, primarily earth moving, grading, road and highway construction and maintenance. In June 1996, KRC Holdings purchased the assets of Medford Ready-Mix Concrete, Inc. located in Medford, Oregon. The acquired company serves the residential and small commercial construction market with ready-mixed concrete and aggregates. Pro forma financial amounts reflecting the effects of the above acquisitions are not presented as such acquisitions were not material to the company's financial position or results of operations. NOTE 15 Employee Benefit Plans The company has noncontributory defined benefit pension plans covering substantially all full-time employees. Pension benefits are based on employee's years of service and earnings. The company makes annual contributions to the plans consistent with the funding requirements of federal law and regulations. Pension expense is summarized as follows: 1996 1995 1994 (In thousands) Service cost/benefits earned during the year $ 3,852 $ 3,538 $ 4,035 Interest cost on projected benefit obligation 10,823 10,784 9,912 Loss (return) on plan assets (24,972) (37,185) 3,154 Net amortization and deferral 11,494 24,407 (15,410) Special termination benefit cost --- 853 --- Total pension costs 1,197 2,397 1,691 Less amounts capitalized 131 184 198 Total pension expense $ 1,066 $ 2,213 $ 1,493 The funded status of the company's plans at December 31 is summarized as follows: 1996 1995 1994 (In thousands) Projected benefit obligation: Vested $122,119 $121,879 $105,561 Nonvested 3,923 4,731 4,124 Accumulated benefit obligation 126,042 126,610 109,685 Provision for future pay increases 24,787 28,114 25,084 Projected benefit obligation 150,829 154,724 134,769 Plan assets at market value 185,872 170,793 139,332 (35,043) (16,069) (4,563) Plus: Unrecognized transition asset 7,336 8,326 9,315 Unrecognized net gains and prior service costs 35,848 14,686 2,466 Accrued pension costs $ 8,141 $ 6,943 $ 7,218 The projected benefit obligation was determined using an assumed discount rate of 7.50 percent (7.25 percent in 1995 and 8 percent in 1994) and assumed long-term rates for estimated compensation increases of 4.50 percent (4.50 percent in 1995 and 5 percent in 1994). The change in these assumptions had the effect of decreasing the projected benefit obligation at December 31, 1996, by $5 million but increasing the projected benefit obligation at December 31, 1995, by $12 million. The assumed long-term rate of return on plan assets is 8.50 percent. Plan assets consist primarily of debt and equity securities. In addition to providing pension benefits, the company has a policy of providing all eligible employees and dependents certain other postretirement benefits which include health care and life insurance upon their retirement. The plans underlying these benefits may require contributions by the employee depending on such employee's age and years of service at retirement or the date of retirement. The accounting for the health care plan anticipates future cost-sharing changes that are consistent with the company's expressed intent to increase retiree contributions each year by the excess of the expected health care cost trend rate over 6 percent. Postretirement benefits expense is summarized as follows: 1996 1995 1994 (In thousands) Service cost/benefits earned during the year $ 1,333 $1,226 $1,454 Interest cost on accumulated postretirement benefit obligation 4,701 4,777 4,584 Return on plan assets (2,491) (183) (176) Amortization of transition obligation 2,458 2,458 2,458 Net amortization and deferral 1,260 (719) 76 Total postretirement benefits cost 7,261 7,559 8,396 Less amounts capitalized 735 442 419 Total postretirement benefits expense $ 6,526 $7,117 $7,977 The funded status of the company's plans at December 31 is summarized as follows: 1996 1995 1994 (In thousands) Accumulated postretirement benefit obligation: Retirees eligible for benefits $40,775 $43,543 $36,985 Active employees fully eligible for benefits --- 66 22 Active employees not fully eligible 24,833 26,229 22,898 Total 65,608 69,838 59,905 Plan assets at market value 21,712 15,095 9,938 43,896 54,743 49,967 Less: Unrecognized transition obligation 39,322 41,779 44,237 Unrecognized net losses 3,693 12,066 4,896 Accrued postretirement benefits cost $ 881 $ 898 $ 834 The health plan cost trend rate assumed in determining the accumulated postretirement benefit obligation at December 31, 1996, was 9 percent decreasing by 1 percent per year until an ultimate rate of 6 percent is reached in 1999 and remaining level thereafter. The health plan cost trend rate assumption has a significant effect on the amounts reported. To illustrate, increasing the assumed health plan cost trend rates by 1 percent each year would increase the accumulated postretirement benefit obligation as of December 31, 1996, by $3.1 million and the aggregate of the service and interest cost components of postretirement benefits expense by $233,000. The accumulated postretirement benefit obligation was determined using an assumed discount rate of 7.50 percent at December 31, 1996, 7.25 percent at December 31, 1995, and 8 percent at December 31, 1994, and assumed long-term rates for estimated compensation increases, as they apply to life insurance benefits, of 4.50 percent at December 31, 1996 and 1995, and 5 percent at December 31, 1994. The change in these assumptions had the effect of decreasing the accumulated postretirement benefit obligation at December 31, 1996, by $2 million but increasing the accumulated postretirement benefit obligation at December 31, 1995, by $7 million. The assumed long-term rate of return on assets is 7.50 percent. Plan assets consist primarily of certain life insurance products of which the return depends on the performance of underlying debt and equity securities. The company has an unfunded, nonqualified benefit plan for executive officers and certain key management employees that provides for defined benefit payments upon the employee's retirement or to their beneficiaries upon death for a 15-year period. Investments consist of life insurance carried on plan participants which is payable to the company upon the employee's death. The cost of these benefits was $2.2 million in 1996, $1.9 million in 1995 and $1.7 million in 1994. The company has a Key Employee Stock Option Plan (KESOP). The company accounts for the KESOP in accordance with APB Opinion No. 25 under which no compensation expense has been recognized. The company is authorized to grant options for up to 1.2 million shares of common stock and has granted options on 484,540 shares through December 31, 1996. Under the KESOP the option price equals the stock's market value on the date of grant. Options automatically vest after nine years, but the KESOP provides for accelerated vesting based upon the attainment of certain performance goals or upon change in control and expire 10 years after the date of grant. The company has contributed $5.7 million to a trust established to fund its commitment under the KESOP. Pro forma net income and earnings per common share calculated using the provisions of SFAS No. 123, "Accounting for Stock-Based Compensation" have not been presented because such amounts are not materially different than actual amounts reported. A summary of the status of the KESOP at December 31, 1996, 1995 and 1994, and changes during the years then ended are as follows: 1996 1995 1994 Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price Balance at 468,737 $17.48 192,284 $15.82 265,964 $15.82 beginning of year Granted --- --- 294,956 18.50 --- --- Forfeited --- --- (2,700) 20.83 (73,680) 15.80 Exercised (44,760) 15.75 (15,803) 15.75 --- --- Balance at end of year 423,977 17.66 468,737 17.48 192,284 15.82 Exercisable at end of year 93,764 $15.75 138,524 $15.75 --- --- Exercise prices on options outstanding at December 31, 1996, range from $15.75 to $18.50 with a weighted average remaining contractual life of approximately 7 years. The weighted average fair value of each option granted in 1995 is $2.67. The fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model. The assumptions used to estimate the fair value of options granted in 1995 were a risk-free interest rate of 7.80 percent, an expected dividend yield of 5.80 percent, an expected life of 10 years and expected volatility of 15.80 percent. The company has Tax Deferred Compensation Savings Plans for eligible employees. Each participant may contribute amounts up to 15 percent of eligible compensation, subject to certain limitations. The company contributes an amount equal to 50 percent of the participant's savings contribution up to a maximum of 6 percent of such participant's contribution. Company contributions were $1.9 million in 1996, 1995 and 1994. NOTE 16 Partnership Investment In September 1995, KRC Holdings through its wholly owned subsidiary, Knife River Hawaii, Inc., acquired a 50 percent interest in Hawaiian Cement, which was previously owned by Lone Star Industries, Inc. Hawaiian Cement is one of the largest construction materials suppliers in Hawaii serving four of the islands. Hawaiian Cement's operations include construction aggregate mining, ready-mixed concrete and cement manufacturing and distribution. Hawaiian Cement, headquartered in Honolulu, Hawaii, is a partnership which is also 50 percent owned by Adelaide Brighton Ltd. of Adelaide, Australia. The company's net investment in Hawaiian Cement is included in "Investments" in the accompanying Consolidated Balance Sheets at December 31, 1996 and 1995, while its share of operating results is included in "Other income -- net" in the accompanying Consolidated Statements of Income for the years ended December 31, 1996 and 1995. Summarized financial information for Hawaiian Cement, which is not consolidated and is accounted for by the equity method, as of and for the year ended December 31, 1996, and as of and for the four months ended December 31, 1995, as applicable, is as follows: 1996 1995 (In thousands) Current assets $17,316 $19,531 Property, plant and equipment, net 52,316 70,544 Current liabilities 10,128 14,209 Other liabilities 14,954 15,736 Net sales 70,059 24,433 Operating margin 9,900 5,096 Income before income taxes 5,373 2,757 The company's investment in Hawaiian Cement exceeds the underlying net assets by $13.2 million. The excess is being amortized over 30 years. NOTE 17 Jointly Owned Facilities The consolidated financial statements include the company's 22.70 percent and 25 percent ownership interests in the assets, liabilities and expenses of the Big Stone Station and the Coyote Station, respectively. Each owner of the Big Stone and Coyote stations is responsible for providing its own financing of its investment in the jointly owned facilities. The company's share of the Big Stone Station and Coyote Station operating expenses is reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income. At December 31, the company's share of the cost of utility plant in service and related accumulated depreciation for the stations was as follows: 1996 1995 1994 (In thousands) Big Stone Station: Utility plant in service $ 48,907 $ 47,687 $ 46,923 Accumulated depreciation 26,676 27,026 25,505 $ 22,231 $ 20,661 $ 21,418 Coyote Station: Utility plant in service $122,320 $122,126 $ 121,784 Accumulated depreciation 52,721 49,296 45,546 $ 69,599 $ 72,830 $ 76,238 NOTE 18 Quarterly Data (Unaudited) The following unaudited information shows selected items by quarter for the years 1996 and 1995: First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per share amounts) 1996 Operating revenues $126,529 $110,213 $133,759 $144,200 Operating expenses 98,447 90,012 103,038 111,679 Operating income 28,082 20,201 30,721 32,521 Net income 13,135 8,600 8,495 15,240 Earnings per common share .45 .30 .29 .53 Average common shares outstanding 28,477 28,477 28,477 28,477 1995 Operating revenues $116,518 $111,267 $113,945 $122,516 Operating expenses 94,047 91,690 91,606 96,327 Operating income 22,471 19,577 22,339 26,189 Net income 10,272 8,662 10,472 12,227 Earnings per common share .35 .30 .36 .42 Average common shares outstanding 28,477 28,477 28,477 28,477 Some of the company's operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Accordingly, quarterly financial information may not be indicative of results for a full year. NOTE 19 Oil and Natural Gas Activities (Unaudited) Fidelity Oil is involved in the acquisition, exploration, development and production of oil and natural gas properties. Fidelity's operations vary from the acquisition of producing properties with potential development opportunities to exploration and are located throughout the United States, the Gulf of Mexico and Canada. Fidelity Oil shares revenues and expenses from the development of specified properties in proportion to its interests. In 1994, Williston Basin undertook a drilling program designed to increase production and to gain updated data from which to assess the future production capabilities of natural gas reserves held primarily in Montana. In late 1994, upon analysis of the results of this program, it was determined that the future production related to these properties can be accelerated and, as a result, the economic value of these reserves has become material to the company's consolidated oil and natural gas production operations. Therefore, beginning in 1994, the tables set forth below include information related to Williston Basin's natural gas production activities. The following information includes the company's proportionate share of all its oil and natural gas interests. The following table sets forth capitalized costs and related accumulated depreciation, depletion and amortization related to oil and natural gas producing activities at December 31: 1996 1995 1994 (In thousands) Subject to amortization $223,409 $173,501 $155,303 Not subject to amortization 6,792 8,831 8,530 Total capitalized costs 230,201 182,332 163,833 Accumulated depreciation, depletion and amortization 71,554 49,498 54,376 Net capitalized costs $158,647 $132,834 $109,457 Net capital expenditures, including those not subject to amortization, related to oil and natural gas producing activities for the 12 months ended December 31 are as follows: 1996 1995 1994 (In thousands) Acquisitions $23,284 $ 9,159 $ 3,182 Exploration 8,101 7,678 12,656 Development 19,979 24,955 20,247 Net capital expenditures $51,364 $41,792 $36,085 The following summary reflects income resulting from the company's operations of oil and natural gas producing activities, excluding corporate overhead and financing costs, for the 12 months ended December 31: 1996 1995 1994 (In thousands) Revenues* $75,335 $53,484 $45,053 Production costs 21,296 16,888 18,463 Depreciation, depletion and amortization 25,629 19,058 13,926 Pretax income 28,410 17,538 12,664 Income tax expense 10,875 6,397 4,257 Results of operations for producing activities $17,535 $11,141 $ 8,407 * Includes $7.0 million, $4.7 million and $7.1 million of revenues for 1996, 1995 and 1994, respectively, related to Williston Basin's natural gas production activities which are included in "Natural gas" operating revenues on the Consolidated Statements of Income. The following table summarizes the company's estimated quantities of proved developed oil and natural gas reserves at December 31, 1996, 1995 and 1994, and reconciles the changes between these dates. Estimates of economically recoverable oil and natural gas reserves and future net revenues therefrom are based upon a number of variable factors and assumptions. For these reasons, estimates of economically recoverable reserves and future net revenues may vary from actual results. 1996 1995 1994 Natural Natural Natural Oil Gas Oil Gas Oil Gas (In thousands of barrels/Mcf) Proved developed and undeveloped reserves: Balance at beginning of year 14,200 179,000 12,500 154,200 11,200 50,300 Production (2,100) (20,400) (2,000) (17,500) (1,600) (9,200) Extensions and discoveries 600 27,000 1,800 23,800 1,300 17,800 Purchases of proved reserves 2,900 9,900 1,100 6,700 600 2,900 Sales of reserves in place (700) (3,700) (300) (200) (400) (2,700) Revisions to previous estimates due to improved secondary recovery techniques and/or changed economic conditions 1,200 8,400 1,100 12,000 1,400 95,100* Balance at end of year 16,100 200,200 14,200 179,000 12,500 154,200 *Includes 99,300 MMcf of Williston Basin's natural gas reserves. Proved developed reserves: January 1, 1994 11,100 43,100 December 31, 1994 12,200 147,200** December 31, 1995 13,600 156,400 December 31, 1996 15,400 168,200 **Includes 98,700 MMcf of Williston Basin's natural gas reserves. Virtually all of the company's interests in oil and natural gas reserves are located in the continental United States. Reserve interests at December 31, 1996, applicable to the company's $2.0 million net investment in oil and natural gas properties located in Canada comprise approximately 2 percent of the total reserves. The standardized measure of the company's estimated discounted future net cash flows of total proved reserves associated with its various oil and natural gas interests at December 31 is as follows: 1996 1995 1994 (In thousands) Future net cash flows before income taxes $580,300 $267,300 $197,900 Future income tax expenses 194,200 76,100 48,800 Future net cash flows 386,100 191,200 149,100 10% annual discount for estimated timing of cash flows 152,100 70,300 54,200 Discounted future net cash flows relating to proved oil and natural gas reserves $234,000 $120,900 $ 94,900 The following are the sources of change in the standardized measure of discounted future net cash flows by year: 1996 1995 1994 (In thousands) Beginning of year $120,900 $ 94,900 $ 71,600 Net revenues from production (54,000) (36,400) (23,800) Change in net realization 125,800 26,300 (4,100) Extensions, discoveries and improved recovery, net of future production-related costs 43,500 31,200 31,700 Purchases of proved reserves 49,600 10,900 5,800 Sales of reserves in place (6,700) (1,000) (3,700) Changes in estimated future development costs -- net of those incurred during the year (2,400) (8,900) (2,900) Accretion of discount 16,900 12,300 8,300 Net change in income taxes (69,200) (17,100) (4,000) Revisions of previous quantity estimates 8,700 8,900 16,500* Other 900 (200) (500) Net change 113,100 26,000 23,300 End of year $234,000 $120,900 $ 94,900 *Includes $19.1 million related to Williston Basin's natural gas reserves. The estimated discounted future cash inflows from estimated future production of proved reserves were computed using year-end oil and natural gas prices. Future development and production costs attributable to proved reserves were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. Future income tax expenses were computed by applying statutory tax rates (adjusted for permanent differences and tax credits) to estimated net future pretax cash flows. To MDU Resources Group, Inc. We have audited the accompanying consolidated balance sheets and statements of capitalization of MDU Resources Group, Inc. (a Delaware corporation) and Subsidiaries as of December 31, 1996, 1995 and 1994, and the related consolidated statements of income and cash flows for each of the three years in the period ended December 31, 1996. 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 audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the 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 audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of MDU Resources Group, Inc. and Subsidiaries as of December 31, 1996, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. /s/ Arthur Andersen LLP Arthur Andersen LLP Minneapolis, Minnesota January 23, 1997 1996 1995 1994 Selected Financial Data Operating revenues: (000's) Electric $ 138,761 $ 134,609 $ 133,953 Natural gas 175,408 167,787 160,970 Construction materials and mining 132,222 113,066 116,646 Oil and natural gas production 68,310 48,784 37,959 $ 514,701 $ 464,246 $ 449,528 Operating income: (000's) Electric $ 29,476 $ 29,898 $ 27,596 Natural gas distribution 11,504 6,917 3,948 Natural gas transmission 30,231 25,427 21,281 Construction materials and mining 16,062 14,463 16,593 Oil and natural gas production 24,252 13,871 8,757 $ 111,525 $ 90,576 $ 78,175 Earnings on common stock: (000's) Electric $ 11,436 $ 12,000 $ 11,719 Natural gas distribution 4,892 1,604 285 Natural gas transmission 2,459 8,416 6,155 Construction materials and mining 11,521 10,819 11,622 Oil and natural gas production 14,375 8,002 9,267 Earnings on common stock before cumulative effect of accounting change 44,683 40,841 39,048 Cumulative effect of accounting change --- --- --- $ 44,683 $ 40,841 $ 39,048 Earnings per common share before cumulative effect of accounting change $ 1.57 $ 1.43 $ 1.37 Cumulative effect of accounting change --- --- --- $ 1.57 $ 1.43 $ 1.37 Pro forma amounts assuming retroactive application of accounting change: Net income (000's) $ 45,470 $ 41,633 $ 39,845 Earnings per common share $ 1.57 $ 1.43 $ 1.37 Common Stock Statistics Weighted average common shares outstanding (000's) 28,477 28,477 28,477 Dividends per common share $ 1.1000 $ 1.0782 $ 1.0533 Book value per common share $ 12.31 $ 11.85 $ 11.49 Market price per common share (year-end) $ 23.00 $ 19.88 $ 18.08 Market price ratios: Dividend payout 70% 76% 77% Yield 4.8% 5.5% 5.9% Price/earnings ratio 14.6x 13.9x 13.2x Market value as a percent of book value 186.8% 167.7% 157.4% Profitability Indicators Return on average common equity 13.0% 12.3% 12.1% Return on average invested capital 9.5% 9.2% 9.1% Interest coverage 5.4x 3.9x 3.3x Fixed charges coverage, including preferred dividends 2.7x 3.0x 2.9x General Total assets (000's) $1,089,173 $1,056,479 $1,004,718 Net long-term debt (000's) $ 280,666 $ 237,352 $ 217,693 Redeemable preferred stock (000's) $ 1,900 $ 2,000 $ 2,100 Capitalization ratios: Common stockholders' investment 54% 57% 58% Preferred stocks 3 3 3 Long-term debt 43 40 39 100% 100% 100% 1993 1992 1991 Selected Financial Data Operating revenues: (000's) Electric $ 131,109 $ 123,908 $128,708 Natural gas 178,981 159,438 173,865 Construction materials and mining 90,397 45,032 41,201 Oil and natural gas production 39,125 33,797 33,939 $ 439,612 $ 362,175 $377,713 Operating income: (000's) Electric $ 30,520 $ 30,188 $ 34,647 Natural gas distribution 4,730 4,509 8,518 Natural gas transmission 20,108 21,331 19,904 Construction materials and mining 16,984 11,532 9,682 Oil and natural gas production 11,750 9,499 12,552 $ 84,092 $ 77,059 $ 85,303 Earnings on common stock: (000's) Electric $ 12,652* $ 13,302 $ 15,292 Natural gas distribution 1,182* 1,370 3,645 Natural gas transmission 4,713 3,479 449 Construction materials and mining 12,359 10,662 9,809 Oil and natural gas production 7,109 5,751 8,010 Earnings on common stock before cumulative effect of accounting change 38,015* 34,564 37,205 Cumulative effect of accounting change 5,521 --- --- $ 43,536 $ 34,564 $ 37,205 Earnings per common share before cumulative effect of accounting change $ 1.34* $ 1.21 $ 1.31 Cumulative effect of accounting change .19 --- --- $ 1.53 $ 1.21 $ 1.31 Pro forma amounts assuming retroactive application of accounting change: Net income (000's) $ 38,817 $ 35,852 $ 37,619 Earnings per common share $ 1.34 $ 1.23 $ 1.29 Common Stock Statistics Weighted average common shares outstanding (000's) 28,477 28,477 28,477 Dividends per common share $ 1.0133 $ .9733 $ .9567 Book value per common share $ 11.17 $ 10.66 $ 10.42 Market price per common share (year-end) $ 21.00 $ 17.58 $ 16.42 Market price ratios: Dividend payout 76%* 80% 73% Yield 5.0% 5.6% 5.8% Price/earnings ratio 15.8x* 14.5x 12.6x Market value as a percent of book value 188.0% 165.0% 157.7% Profitability Indicators Return on average common equity 12.3%* 11.6% 12.7% Return on average invested capital 9.4%* 8.7% 9.6% Interest coverage 3.4x* 3.3x 3.8x** Fixed charges coverage, including preferred dividends 3.0x* 2.4x 2.4x General Total assets (000's) $1,041,051 $1,024,510 $964,691 Net long-term debt (000's) $ 231,770 $ 249,845 $220,623 Redeemable preferred stock (000's) $ 2,200 $ 2,300 $ 2,400 Capitalization ratios: Common stockholders' investment 56% 53% 56% Preferred stocks 3 3 3 Long-term debt 41 44 41 100% 100% 100% * Before cumulative effect of an accounting change reflecting the accrual of estimated unbilled revenues. ** Calculation reflects the provisions of the company's restatement of its Indenture of Mortgage effective April 1992. 1996 1995 1994 Electric Operations Sales to ultimate consumers (thousand kWh) 2,067,926 1,993,693 1,955,136 Sales for resale (thousand kWh) 374,535 408,011 444,492 Electric system generating and firm purchase capability--kW (Interconnected system) 481,800 472,400 470,900 Demand peak--kW (Interconnected system) 393,300 412,700 369,800 Electricity produced (thousand kWh) 1,829,669 1,718,077 1,901,119 Electricity purchased (thousand kWh) 809,261 867,524 700,912 Cost of fuel and purchased power per kWh $.017 $.016 $.017 Natural Gas Distribution Operations Sales (Mdk) 38,283 33,939 31,840 Transportation (Mdk) 9,423 11,091 9,278 Weighted average degree days--% of previous year's actual 114% 105% 92% Natural Gas Transmission Operations Sales for resale (Mdk) --- --- --- Transportation (Mdk) 82,169 68,015 63,870 Produced (Mdk) 6,073 4,981 4,732 Net recoverable reserves (MMcf) 133,400 113,000 99,300 Energy Marketing Operations Natural gas volumes (Mdk) 4,670 3,556 7,301 Propane (thousand gallons) 9,689 7,471 6,462 Construction Materials and Mining Operations Construction materials: (000's) Aggregates (tons sold) 3,374 2,904 2,688 Asphalt (tons sold) 694 373 391 Ready-mixed concrete (cubic yards sold) 340 307 315 Recoverable aggregate reserves (tons) 119,800 68,000 71,000 Coal: (000's) Sales (tons) 2,899 4,218 5,206 Recoverable reserves (tons) 228,900 231,900 236,100 Oil and Natural Gas Production Operations Production: Oil (000's of barrels) 2,149 1,973 1,565 Natural gas (MMcf) 14,067 12,319 9,228 Average sales prices: Oil (per barrel) $17.91 $15.07 $13.14 Natural gas (per Mcf) $ 2.09 $ 1.51 $ 1.84 Net recoverable reserves: Oil (000's of barrels) 16,100 14,200 12,500 Natural gas (MMcf) 66,800 66,000 54,900 1993 1992 1991 Electric Operations Sales to ultimate consumers (thousand kWh) 1,893,713 1,829,933 1,877,634 Sales for resale (thousand kWh) 510,987 352,550 331,314 Electric system generating and firm purchase capability--kW (Interconnected system) 465,200 460,200 454,400 Demand peak--kW (Interconnected system) 350,300 339,100 387,100 Electricity produced (thousand kWh) 1,870,740 1,774,322 1,736,187 Electricity purchased (thousand kWh) 701,736 593,612 611,884 Cost of fuel and purchased power per kWh $.016 $.016 $.016 Natural Gas Distribution Operations Sales (Mdk) 31,147 26,681 30,074 Transportation (Mdk) 12,704 13,742 12,261 Weighted average degree days--% of previous year's actual 115% 98% 101% Natural Gas Transmission Operations Sales for resale (Mdk) 13,201 16,841 19,572 Transportation (Mdk) 59,416 64,498 53,930 Produced (Mdk) 3,876 3,551 3,742 Net recoverable reserves (MMcf) --- --- --- Energy Marketing Operations Natural gas volumes (Mdk) 6,827 3,292 991 Propane (thousand gallons) 2,210 --- --- Construction Materials and Mining Operations Construction materials: (000's) Aggregates (tons sold) 2,391 263 --- Asphalt (tons sold) 141 --- --- Ready-mixed concrete (cubic yards sold) 157 --- --- Recoverable aggregate reserves (tons) 74,200 20,600 --- Coal: (000's) Sales (tons) 5,066 4,913 4,731 Recoverable reserves (tons) 230,600 235,700 256,700 Oil and Natural Gas Production Operations Production: Oil (000's of barrels) 1,497 1,531 1,491 Natural gas (MMcf) 8,817 5,024 2,565 Average sales prices: Oil (per barrel) $14.84 $16.74 $19.90 Natural gas (per Mcf) $ 1.86 $ 1.53 $ 1.48 Net recoverable reserves: Oil (000's of barrels) 11,200 12,200 11,600 Natural gas (MMcf) 50,300 37,200 27,500 EX-21 7 SUBSIDIARIES SUBSIDIARIES OF MDU RESOURCES GROUP, INC. December 31, 1996 State or Other Jurisdiction in Which Incorporated Alaska Basic Industries, Inc. Alaska Anchorage Sand and Gravel Company, Inc. Alaska Baldwin Contracting Company, Inc. California Centennial Energy Holdings, Inc. Delaware Concrete, Inc. California Customer One, Inc. Delaware Fidelity Oil Co. Delaware Fidelity Oil Holdings, Inc. Delaware KRC Aggregate, Inc. Delaware KRC Holdings, Inc. Delaware Knife River Corporation Minnesota Knife River Hawaii, Inc. Delaware Knife River Marine, Inc. Delaware LTM, Incorporated Oregon Medford Ready Mix, Inc. Delaware Prairie Propane, Inc. Delaware Prairielands Energy Marketing, Inc. Delaware Rogue Aggregates, Inc. Oregon WBI Canadian Pipeline, Ltd. Canada Williston Basin Interstate Pipeline Company Delaware EX-23.A,EX-23.B,EX-2 8 CONSENTS CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference in this Form 10-K of our report dated January 23, 1997, included in the MDU Resources Group, Inc. Annual Report to Stockholders for 1996. We also consent to the incorporation of our report incorporated by reference in this Form 10-K into the Company's previously filed Registration Statements on Form S-3, No. 33-46605, No. 33-66682 and No. 333-06127, and on Form S-8, No. 33-54486, No. 33-53896, No. 33-53898, No. 333-06103 and No. 33-06105. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Minneapolis, Minnesota February 28, 1997 CONSENT OF ENGINEER We hereby consent to the reference to our reports dated January 9 and 31, 1997, appearing in this Annual Report on Form 10-K. We also consent to the incorporation by reference in the Registration Statements on Form S-3, No. 33-46605, No. 33-66682, and No. 333-06127 and on Form S-8, No. 33-54486, No. 33-53896, No. 33-53898, No. 333-06103 and No. 333-06105 of MDU Resources Group, Inc. and in the related Prospectuses of the reference to such reports appearing in this Annual Report on Form 10-K. /s/ RALPH E. DAVIS ASSOCIATES, INC. RALPH E. DAVIS ASSOCIATES, INC. Houston, Texas February 28, 1997 CONSENT OF ENGINEER We hereby consent to the reference to our report dated May 9, 1994, appearing in this Annual Report on Form 10-K. We also consent to the incorporation by reference in the Registration Statements on Form S-3, No. 33-46605, No. 33-66682 and No. 333-06127, and on Form S-8, No. 33-54486, No. 33-53896, No. 33-53898, No. 333-06103, and No. 333-06105 of MDU Resources Group, Inc. and in the related Prospectuses of the reference to such report appearing in this Annual Report on Form 10-K. /s/ WEIR INTERNATIONAL MINING CONSULTANTS WEIR INTERNATIONAL MINING CONSULTANTS Des Plaines, Illinois February 28, 1997 EX-27 9 FINANCIAL DATA SCHEDULE
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED STATEMENTS OF INCOME, CONSOLIDATED BALANCE SHEETS AND CONSOLIDATED STATEMENTS OF CASH FLOW AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000067716 MDU RESOURCES GROUP, INC. 1000 US 12-MOS DEC-31-1996 JAN-01-1996 DEC-31-1996 1 PER-BOOK 518,857 287,233 191,658 54,192 37,233 1,089,173 94,828 64,305 191,541 350,674 1,800 15,000 346,960 1,950 0 2,000 11,754 100 0 0 358,935 1,089,173 514,701 16,087 403,176 419,263 95,438 (15,466) 79,972 34,502 45,470 787 44,683 31,326 34,502 106,238 1.57 0
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