-----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, Q0M91Wq4tundA3iIseJkFbaPYNO5hYvGyon+zLgyGt60lF6//SzAaFnAD16CNyx3 aDSv5IZ5Np6HcPTvPmV3NA== 0000067716-98-000009.txt : 19980309 0000067716-98-000009.hdr.sgml : 19980309 ACCESSION NUMBER: 0000067716-98-000009 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980306 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: SEC FILE NUMBER: 001-03480 FILM NUMBER: 98558722 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 1997 FORM 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, 1997 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) Schuchart Building 918 East Divide Avenue 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 27, 1998: $901,622,000. Indicate the number of shares outstanding of each of the Registrant's classes of common stock, as of February 27, 1998: 29,143,332 shares. DOCUMENTS INCORPORATED BY REFERENCE. 1. Pages 25 through 51 of the Annual Report to Stockholders for 1997, incorporated in Part II, Items 6 and 8 of this Report. 2. Proxy Statement, dated March 9, 1998, 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 Corporation -- 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 7A -- Quantitative and Qualitative Disclosures About Market Risk 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 statements that are identified by 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 Schuchart Building, 918 East Divide Avenue, 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), the Fidelity Oil Group (Fidelity Oil) and Utility Services, Inc. (Utility Services). 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, 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 Alaska, California, Hawaii and Oregon. In addition, Knife River surface mines and markets low sulfur lignite coal at mines located in Montana and North Dakota. 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. Utility Services, through its wholly owned subsidiaries, International Line Builders, Inc. and High Line Equipment, Inc., both acquired on July 1, 1997, installs and repairs electric transmission and distribution power lines in the western United States and Hawaii and provides related supplies and equipment. 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, 1997, the Company had 2,218 full-time employees with 84 employed at MDU Resources Group, Inc., including Fidelity Oil, 1,011 at Montana-Dakota, 292 at Williston Basin, including Prairielands, 522 at Knife River's construction materials operations, 147 at Knife River's coal operations and 162 at Utility Services. Approximately 501 and 83 of the Montana-Dakota and Williston Basin employees, respectively, are represented by the International Brotherhood of Electrical Workers (IBEW). Labor contracts with such employees are in effect through May 1999, for both Montana-Dakota and Williston Basin. 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 90 employees. In addition, Knife River has 14 labor contracts which represent 243 of its construction materials employees. Utility Services has 2 labor contracts representing the majority of its 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" and Notes to Consolidated Financial Statements. Any reference to the Company's Consolidated Financial Statements and Notes thereto shall be to pages 25 through 49 in the Company's Annual Report to Stockholders for 1997 (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 over 113,000 residential, commercial, industrial and municipal customers located in 177 communities and adjacent rural areas as of December 31, 1997. 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, 1997, Montana-Dakota's net electric plant investment approximated $283.9 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 1997 electric utility operating revenues by jurisdiction is as follows: North Dakota -- 60 percent; Montana -- 22 percent; South Dakota -- 8 percent and Wyoming -- 10 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 421,060 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, 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: 1997 Net Generation Nameplate Summer (kilowatt- Generating Rating Capability hours in Station Type (kW) (kW) thousands) North Dakota -- Coyote* Steam 103,647 106,750 507,714 Heskett Steam 86,000 102,000 369,791 Williston Combustion Turbine 7,800 8,900 (62)** South Dakota -- Big Stone* Steam 94,111 101,460 741,280 Montana -- Lewis & Clark Steam 44,000 49,150 184,408 Glendive Combustion Turbine 34,780 31,200 13,484 Miles City Combustion Turbine 23,150 21,600 10,155 393,488 421,060 1,826,770 * Reflects Montana-Dakota's ownership interest. ** Station use, to meet MAPP's accreditation requirements, exceeded generation. 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, 1993, through December 31, 1997, 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, 1997 1996 1995 1994 1993 Average cost of coal per million Btu $.95 $.93 $.94 $.97 $.96 Average cost of coal per ton $14.22 $13.64 $12.90 $12.88 $12.78 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 1997 summer peak was only 404,566 kW. The 1997 summer peak, assuming normal weather, was previously forecasted to have been approximately 416,600 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 2003 will approximate 1.3 percent annually. Montana- Dakota's latest forecast indicates that its kilowatt-hour (kWh) sales growth rate, on a normalized basis, through 2003 will approximate 1.0 percent annually. Montana-Dakota currently estimates that it has adequate capacity available through existing generating stations and long-term firm purchase contracts until the year 2000. If additional capacity is needed in 2000 or after, it will be met through the addition of combustion turbine peaking stations and purchases from the Mid-Continent Area Power Pool (MAPP) on an intermediate-term basis. Montana-Dakota has major interconnections with its neighboring utilities, all of which are 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 is supplied through an interconnection with Black Hills Power and Light Company 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. As a result of competition in electric generation, wholesale power markets have become increasingly competitive and evaluations are ongoing concerning retail competition. In April 1996, the FERC issued its final rules (Order No. 888 and 889) on wholesale electric transmission open access and recovery of stranded costs. Montana-Dakota filed proposed tariffs with the FERC in compliance with Order 888, which became effective in July 1996. Montana-Dakota is awaiting final approval of the proposed tariffs by the FERC. In December 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. On May 29, 1997, Montana-Dakota's request was granted. In a related matter, in March 1996, the MAPP, of which Montana- Dakota is a member, filed a restated operating agreement with the FERC. The FERC approved MAPP's restated agreement, excluding MAPP's market-based rate proposal, effective November 1996. The FERC has requested additional information from the MAPP on its market-based rate proposal before it will take further action. Three of the four states which regulate the Company's electric operations continue to evaluate and/or implement utility regulations with respect to retail competition (retail wheeling). Additionally, federal legislation addressing this issue has been introduced. In April 1997, the Montana legislature passed an electric industry restructuring bill. The bill provides for full customer choice of electric supplier by July 1, 2002, stranded cost recovery and other provisions. Based on the provisions of such restructuring bill, because the Company's utility division operates in more than one state, the Company has the option of deferring its transition to full customer choice until 2006. In its 1997 legislative session, the North Dakota legislature established an Electric Industry Competition Committee to study over a six-year period the impact of competition on the generation, transmission and distribution of electric energy in the State. In 1997, the WPSC selected a consultant to perform a study on the impact of electric restructuring in Wyoming. The study found no material economic benefits; however, the WPSC is continuing to evaluate the economic impact of retail wheeling on the State of Wyoming. The SDPUC has not initiated any proceedings to date concerning retail competition or electric industry restructuring. Although Montana-Dakota is unable to predict the outcome of such regulatory proceedings or legislation, or the extent to which retail competition may occur, 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 load management costs. In Montana (22 percent of electric revenues), such cost changes are includible in general rate filings. Capital Requirements -- The following schedule (in millions of dollars) summarizes the 1997 actual and 1998 through 2000 anticipated net capital expenditures applicable to Montana-Dakota's electric operations: Actual Estimated 1997 1998 1999 2000 Production $ 4.7 $ 5.8 $ 5.5 $ 5.9 Transmission 2.6 2.8 2.7 2.9 Distribution, General and Common 11.4 9.0 8.2 8.2 $18.7 $17.6 $16.4 $17.0 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). The co-owners of the Big Stone Station have determined the modifications necessary at the Big Stone Station. Montana-Dakota believes that the cost of such modifications will not have a material effect on its results of operations. 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 1997 and does not expect to incur any significant capital expenditures related to environmental compliance through 2000. 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 141 communities and adjacent rural areas as of December 31, 1997, and provides natural gas transportation services to certain customers on its system. These services are provided through a distribution system aggregating over 4,200 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, 1997, Montana-Dakota's net natural gas and propane distribution plant investment approximated $79.5 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 1997 natural gas and propane utility operating revenues by jurisdiction is as follows: North Dakota -- 43 percent; Montana -- 29 percent; South Dakota -- 21 percent and Wyoming -- 7 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 the weather. 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, 1997 1996 1995 1994 1993 Mdk (thousands of decatherms) Sales: Residential 20,126 22,682 20,135 19,039 19,565 Commercial 13,799 15,325 13,509 12,403 11,196 Industrial 395 276 295 398 386 Total 34,320 38,283 33,939 31,840 31,147 Transportation: Commercial 1,612 1,677 1,742 2,011 3,461 Industrial 8,455 7,746 9,349 7,267 9,243 Total 10,067 9,423 11,091 9,278 12,704 Total Throughput 44,387 47,706 45,030 41,118 43,851 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 monthly 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. Capital Requirements -- Montana-Dakota's net capital expenditures aggregated $7.7 million for natural gas and propane distribution facilities in 1997 and are anticipated to be approximately $7.7 million, $8.8 million and $7.5 million in 1998, 1999 and 2000, 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 as set forth 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 22 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. Prairielands, a subsidiary of Williston Basin, seeks new energy markets while continuing to expand present markets for natural gas. Its activities include buying and selling natural gas and arranging transportation services to end users, pipelines and local distribution companies. In addition, Prairielands operates two retail propane operations in north central and southeastern North Dakota. At December 31, 1997, the net natural gas transmission plant investment, inclusive of its transmission, storage, gathering, production, marketing and propane facilities, was approximately $167.5 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 1997, represented 87 percent of Williston Basin's currently subscribed firm transportation capacity. In November 1996, Montana-Dakota executed a new firm transportation agreement with Williston Basin for a term of five years which began in July 1997. In addition, in July 1995, Montana-Dakota entered a twenty-year contract 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 1995 through 1997, 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 1997, 1996 and 1995 is as follows: 1997 1996 1995 Production (MMcf) 7,215 6,324 5,184 Average sales price $1.30 $1.11 $.91 Production costs, including taxes $.46 $.43 $.30 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, 1997, are as follows: Gross Net Productive Wells 533 483 Developed Acreage (000's) 234 213 Undeveloped Acreage (000's) 45 40 The following table shows the results of natural gas development wells drilled and tested during 1997, 1996 and 1995: 1997 1996 1995 Productive 20 32 17 Dry Holes --- --- --- Total 20 32 17 At December 31, 1997, there were no wells in the process of drilling. Williston Basin's recoverable proved developed and undeveloped natural gas reserves approximated 127.3 Bcf at December 31, 1997. These amounts are supported by a report dated January 12, 1998, prepared by Ralph E. Davis Associates, Inc., an independent firm of petroleum and natural gas engineers. Since 1993, Williston Basin has engaged in a long-term developmental drilling program to enhance the performance of its investment in natural gas reserves. As a result of this effort, 1997 production levels reached 6.9 MMdk, up 79 percent from 1993. The production increases from these reserves are expected to provide additional natural gas supplies for Prairielands to enable it to enhance its marketing efforts. For additional information related to Williston Basin's natural gas interests, see Note 18 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 totaled approximately $19 million or, under its alternative pricing theory, approximately $39 million. On June 26, 1997, the Federal District Court issued its order awarding Moncrief damages of approximately $15.6 million. On July 25, 1997, the Federal District Court issued an order limiting Moncrief's reimbursable costs to post-judgment interest, instead of both pre- and post-judgment interest as Moncrief had sought. On August 25, 1997, Moncrief filed a notice of appeal with the United States Court of Appeals for the Tenth Circuit related to the Federal District Court's orders. On September 2, 1997, Williston Basin and the Company filed a notice of cross-appeal. Williston Basin believes that it is entitled to recover from ratepayers virtually all of the costs ultimately incurred as a result of these orders as gas supply realignment transition costs pursuant to the provisions of the FERC's Order 636. However, the amount of costs that can ultimately be recovered is subject to approval by the FERC and market conditions. In December 1993, Apache Corporation (Apache) and Snyder Oil Corporation (Snyder) filed suit in North Dakota Northwest Judicial District Court (North Dakota District Court), against Williston Basin and the Company. Apache and Snyder are oil and natural gas producers which 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 as Williston Basin, the Company and Koch have settled their disputes. Apache and Snyder have recently provided alleged damages under differing theories ranging up to $4.8 million without interest. A motion to intervene in the case by several other producers, all of which had contracts with Koch but not with Williston Basin, was denied in December 1996. The trial before the North Dakota District Court was completed on November 6, 1997. Williston Basin and the Company are awaiting a decision from the North Dakota District Court. In a related matter, on March 14, 1997, a suit was filed by nine other producers, several of which had unsuccessfully tried to intervene in the Apache and Snyder litigation, against Koch, Williston Basin and the Company. The parties to this suit are making claims similar to those in the Apache and Snyder litigation, although no specific damages have been specified. In Williston Basin's opinion, the claims of Apache and Snyder are without merit and overstated and the claims of the nine other producers are without merit. If any amounts are ultimately found to be due, Williston Basin plans to file with the FERC for recovery from ratepayers. 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. On October 20, 1997, Williston Basin appealed to the U.S. District Court of Appeals for the D.C. Circuit certain issues decided by the FERC in prior orders concerning the 1992 proceeding. On December 10, 1997, the FERC issued an order accepting, subject to certain conditions, Williston Basin's July 25, 1997 compliance filing. On December 22, 1997, Williston Basin submitted a compliance filing pursuant to the FERC's December 10, 1997 order. On December 31, 1997, Williston Basin refunded $33.8 million to its customers, including $30.8 million to Montana-Dakota, in addition to the $6.1 million interim refund that it had previously made in November 1996. All such amounts had been previously reserved. Williston Basin is awaiting an order from the FERC on its December 22, 1997 compliance filing. 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 and is awaiting a final order from the FERC. Reserves have been provided for a portion of the revenues that have been collected subject to refund with respect to pending regulatory proceedings and 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 and $6.0 million in 1996 and 1995, respectively. The costs incurred in 1997 were not material and are included in "Other income -- net" on the Consolidated Statements of Income. 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 which in December 1996 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 as to the appropriate costs to be allocated. Williston Basin sells and transports natural gas held under the repurchase commitment. 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 43.0 MMdk of this gas to its then current 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. At December 31, 1997 and 1996, natural gas held under a repurchase commitment of $14.6 million and $37.2 million, respectively, is included in the Company's Consolidated Balance Sheets under "Deferred charges and other assets". The recognition of the then current market value of this natural gas facilitated the sale by Williston Basin of 28.1 MMdk from the date of this write-down through December 31, 1997, and should allow Williston Basin to market the remaining 14.9 MMdk on a sustained basis enabling Williston Basin to liquidate this asset over approximately the next three to four years. Capital Requirements -- The following schedule (in millions of dollars) summarizes the 1997 actual and 1998 through 2000 anticipated net capital expenditures, excluding potential acquisitions, applicable to Williston Basin's consolidated operations: Actual Estimated 1997 1998 1999 2000 Production and Gathering $ 4.8 $11.4 $14.2 $12.3 Underground Storage .3 .4 .3 .8 Transmission 3.6 3.2 11.4 4.6 General and Other 1.5 6.2 1.3 1.4 Energy Marketing .2 .3 .2 1.3 $10.4 $21.5 $27.4 $20.4 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 mine, process and sell construction aggregates (crushed rock, 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. On February 14, 1997, Baldwin Contracting Company, Inc. (Baldwin), a subsidiary of KRC Holdings, purchased the physical assets of Orland Asphalt located in Orland, California, including a hot-mix plant and aggregate reserves. Orland Asphalt was combined with and operates as part of Baldwin. On July 31, 1997, Knife River purchased the 50 percent interest in Hawaiian Cement, that it did not previously own, from Adelaide Brighton Cement (Hawaii), Inc. of Adelaide, Australia. The Company's initial 50 percent partnership interest in Hawaiian Cement was acquired in September 1995. On March 5, 1998, the Company acquired Morse Bros., Inc. and S2 - F Corp., privately-held construction materials companies located in Oregon's Willamette Valley. See Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations" for more information regarding these acquisitions. Knife River's construction materials business has continued to grow since its first acquisition in 1992 and now comprises the majority of Knife River's business. Knife River continues to investigate 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. For information regarding sales volumes and revenues for the construction materials operations for 1995 through 1997, 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 influence 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 1997, 1996 and 1995, 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, 1997 1996 1995 1994 1993 (In thousands) Tons sold: Montana-Dakota generating stations 530 528 453 691 624 Jointly-owned generating stations -- Montana-Dakota's share 434 565 883 1,049 1,034 Others 1,303 1,695 2,767 3,358 3,299 Industrial and other sales 108 111 115 108 109 Total 2,375 2,899 4,218 5,206 5,066 Revenues $27,906 $32,696 $39,956 $45,634 $44,230 The decrease in total tons sold in 1997 compared to 1996, reflected in the above table, is the result of lower tons sold to the Coyote Station due to a ten-week maintenance outage. See Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations" for more information regarding the sales volumes and revenues for the coal operations for 1995 through 1997. In recent years, in response to competitive pressures from other mines, Knife River has limited its coal price increases to less than those 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. Effective January 1, 1998, Montana-Dakota and Knife River agreed to a new five year coal contract for Montana-Dakota's Lewis & Clark generating station. In 1997, Knife River supplied approximately 180,000 tons of coal to this station. 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 have 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 that 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 the Co-owners are seeking damages in an unspecified amount. In January 1996, the Company and Knife River filed separate motions with the State District Court to dismiss or stay, pending arbitration. In May 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. In September 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. By order dated April 25, 1997, the arbitration panel concluded that the claims raised by the Co-owners are arbitrable. The Co-owners have 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, of 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. By letter dated May 14, 1997, Knife River requested permission to move for summary judgment which permission was granted by the arbitration panel over objections of the Co-owners. Knife River filed its summary judgment motion on July 21, 1997, which motion was denied on October 29, 1997. 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 1997 actual net capital expenditures, including those expended for the acquisitions of Orland Asphalt and the 50 percent interest in Hawaiian Cement that Knife River did not previously own, and 1998 through 2000 anticipated net capital expenditures, excluding potential acquisitions, applicable to Knife River's consolidated construction materials and mining operations: Actual Estimated 1997 1998 1999 2000 Construction Materials $38.0 $22.8 $10.2 $ 7.1 Coal 2.6 5.0 1.4 3.0 $40.6 $27.8 $11.6 $10.1 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 U.S. 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 award of punitive damages. Hawaiian Cement is a Hawaiian general partnership whose general partners are now Knife River Hawaii, Inc. and Knife River Dakota, Inc., indirect wholly owned subsidiaries of the Company. Knife River Dakota, Inc. purchased its partnership interest from Adelaide Brighton Cement (Hawaii), Inc. on July 31, 1997. Unitek sought civil penalties under the Clean Air Act (as described below), and up to $20 million in damages for various claims (as described above). In August 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. In September 1996, Unitek and Hawaiian Cement reached a settlement which resolved all claims except as to Clean Air Act penalties. 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 continued to negotiate the remaining Clean Air Act claims. In May 1996, the EPA issued a Notice of Violation (NOV) to Hawaiian Cement. The NOV stated 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. On April 7, 1997, a settlement resolving the remaining Clean Air Act claims and the EPA's NOV issued in May 1996, was reached by Hawaiian Cement, the EPA and Unitek. On February 11, 1998, the District Court approved the April 1997 settlement. The costs relating to both the September 1996 and April 1997 settlements were not material and did not affect the Company's results of operations since reserves had previously been provided. Reserve Information -- As of December 31, 1997, the combined construction materials operations had under ownership or lease approximately 169 million tons of recoverable aggregate reserves. As of December 31, 1997, Knife River had under ownership or lease, reserves of approximately 227 million tons of recoverable lignite coal, 87 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 1997 production. Knife River estimates that approximately 64 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 exploratory drilling 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. Fidelity's oil and natural gas activities have continued to expand since the mid-1980's. Fidelity continues to seek additional reserve and production opportunities through the direct acquisition of producing properties and through exploratory drilling opportunities, as well as routine development of its existing properties. Future growth is dependent upon continuing success in these endeavors. 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 1997, 1996 and 1995, are as follows: 1997 1996 1995 Oil: Production (000's of barrels) 2,088 2,149 1,973 Average sales price $17.50 $17.91 $15.07 Natural Gas: Production (MMcf) 13,192 14,067 12,319 Average sales price $2.41 $2.09 $1.51 Production costs, including taxes, per net equivalent barrel $3.65 $3.31 $3.18 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, 1997, are as follows: Gross Net Productive Wells: Oil 2,279 138 Natural Gas 462 26 Total 2,741 164 Developed Acreage (000's) 614 56 Undeveloped Acreage (000's) 1,085 83 Exploratory and Development Wells -- The following table shows the results of oil and natural gas wells drilled and tested during 1997, 1996 and 1995: Net Exploratory Net Development Productive Dry Holes Total Productive Dry Holes Total Total 1997 1 2 3 3 1 4 7 1996 1 2 3 4 --- 4 7 1995 3 2 5 8 1 9 14 At December 31, 1997, there were six gross wells in the process of drilling, four of which were exploratory wells and two of which were development wells. 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 1997, 1996 and 1995: 1997 1996 1995 Acquisitions $ --- $23.2 $ 9.1 Exploration 13.4 8.1 7.7 Development 15.4 15.9 22.2 $28.8 $47.2 $39.0 Fidelity Oil's net capital expenditures are anticipated to be approximately $50 million for 1998 and $60 million for both 1999 and 2000. Reserve Information -- Fidelity Oil's recoverable proved developed and undeveloped oil and natural gas reserves approximated 14.9 million barrels and 57.6 Bcf, respectively, at December 31, 1997. Of these amounts, 10.2 million barrels and 2.8 Bcf, as supported by a report dated January 12, 1998, prepared by Ralph E. Davis Associates, Inc., an independent firm of petroleum and natural gas engineers, were related to its properties located in southeastern Montana and southcentral Alabama. For additional information related to Fidelity Oil's oil and natural gas interests, see Note 18 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. In a related matter, Williston Basin has been named in a suit filed by nine other producers related to a natural gas purchase contract. 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. On February 11, 1998, the District Court approved the April 1997 settlement which was reached by Hawaiian Cement, the EPA and Unitek. 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 1997. 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 1997 and 1996 and dividends declared thereon were as follows: Common Common Common Stock Stock Price Stock Price Dividends (High) (Low) Per Share 1997 First Quarter $23.00 $21.00 $ .2775 Second Quarter 25.25 21.38 .2775 Third Quarter 27.69 22.25 .2875 Fourth Quarter 33.50 26.63 .2875 $1.1300 1996 First Quarter $23.00 $19.88 $ .2725 Second Quarter 23.50 20.13 .2725 Third Quarter 22.38 20.75 .2775 Fourth Quarter 23.38 21.25 .2775 $1.1000 As of December 31, 1997, the Company's common stock was held by approximately 13,600 stockholders of record. ITEM 6. SELECTED FINANCIAL DATA Reference is made to Selected Financial Data on pages 50 and 51 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 For purposes of segment financial reporting and discussion of results of operations, Electric includes the electric operations of Montana-Dakota, as well as the operations of Utility Services. Natural Gas Distribution includes Montana-Dakota's natural gas distribution operations. Natural Gas Transmission includes Williston Basin's storage, transportation, gathering and natural gas production operations, and the energy marketing operations of its subsidiary, Prairielands. Construction Materials and Mining includes the results of Knife River's operations, while Oil and Natural Gas Production includes the operations of Fidelity Oil. 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 1997 1996 1995 Electric $ 13.4 $ 11.4 $ 12.0 Natural gas distribution 4.5 4.9 1.6 Natural gas transmission 11.3 2.5 8.4 Construction materials and mining 10.1 11.5 10.8 Oil and natural gas production 14.5 14.4 8.0 Earnings on common stock $ 53.8 $ 44.7 $ 40.8 Earnings per common share -- basic $ 1.86 $ 1.57 $ 1.43 Earnings per common share -- diluted $ 1.86 $ 1.57 $ 1.43 Return on average common equity 14.6% 13.0% 12.3% 1997 compared to 1996 Consolidated earnings for 1997 increased $9.1 million when compared to 1996. This increase includes the effect of the one-time adjustment in the third quarter of 1996 of $3.7 million or 13 cents per common share, reflecting the write-down to market value of natural gas being held under a repurchase commitment and certain reserve adjustments. The improvement is attributable to increased earnings from the natural gas transmission, electric and oil and natural gas production businesses, partially offset by a decrease in construction materials and mining and natural gas distribution earnings. 1996 compared to 1995 Consolidated earnings for 1996 were up $3.9 million when compared to 1995 including the effect of the $3.7 million net charge, previously described. The increase was the result of higher earnings at the oil and natural gas production, natural gas distribution and construction materials and mining businesses. Decreased earnings at the electric and natural gas transmission businesses somewhat offset the earnings improvement. ________________________________ 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. Electric Operations Years ended December 31, 1997* 1996 1995 Operating revenues: Retail sales $ 130.3 $ 128.8 $ 124.4 Sales for resale and other 11.3 10.0 10.2 Utility services 22.8 --- --- 164.4 138.8 134.6 Operating expenses: Fuel and purchased power 45.6 44.0 41.8 Operation and maintenance 60.1 41.4 40.1 Depreciation, depletion and amortization 17.8 17.1 16.3 Taxes, other than income 7.8 6.8 6.5 131.3 109.3 104.7 Operating income $ 33.1 $ 29.5 $ 29.9 Retail sales (kWh) 2,041.2 2,067.9 1,993.7 Sales for resale (kWh) 361.9 374.6 408.0 Cost of fuel and purchased power per kWh $ .018 $ .017 $ .016 * Includes International Line Builders, Inc. and High Line Equipment, Inc. which were acquired on July 1, 1997. Natural Gas Distribution Operations Years ended December 31, 1997 1996 1995 Operating revenues: Sales $ 153.6 $ 151.5 $ 146.8 Transportation and other 3.4 3.5 3.7 157.0 155.0 150.5 Operating expenses: Purchased natural gas sold 107.2 102.7 102.6 Operation and maintenance 28.5 30.0 30.4 Depreciation, depletion and amortization 7.0 6.9 6.7 Taxes, other than income 3.9 3.9 3.9 146.6 143.5 143.6 Operating income $ 10.4 $ 11.5 $ 6.9 Volumes (dk): Sales 34.3 38.3 33.9 Transportation 10.1 9.4 11.1 Total throughput 44.4 47.7 45.0 Degree days (% of normal) 99.3% 116.2% 101.6% Average cost of natural gas, including transportation, per dk $ 3.12 $ 2.67 $ 3.02 Natural Gas Transmission Operations Years ended December 31, 1997* 1996 1995 Operating revenues: Transportation $ 51.4** $ 60.4** $ 54.1** Storage 10.9 10.7 12.6 Natural gas production and other 4.5 7.5 5.2 Energy marketing 26.6 --- --- 93.4 78.6 71.9 Operating expenses: Purchased gas sold 17.9 --- --- Operation and maintenance 35.5** 37.2** 35.7** Depreciation, depletion and amortization 5.5 6.7 7.0 Taxes, other than income 5.3 4.5 3.8 64.2 48.4 46.5 Operating income $ 29.2 $ 30.2 $ 25.4 Volumes (dk): Transportation -- Montana-Dakota 35.5 43.4 35.4 Other 50.0 38.8 32.6 85.5 82.2 68.0 Produced (000's of dk) 6,949 6,073 4,981 * Effective January 1, 1997, Prairielands became a wholly owned subsidiary of Williston Basin. Consolidated financial results are presented for 1997. In 1996 and 1995, Prairielands' financial results were included with the natural gas distribution business. ** Includes amortization and related recovery of deferred natural gas contract buy-out/ buy-down and gas supply realignment costs $ 5.5 $ 10.6 $ 11.4 Construction Materials and Mining Operations*** Years ended December 31, 1997 1996 1995 Operating revenues: Construction materials $ 146.2 $ 99.5 $ 73.1 Coal 27.9 32.7 39.9 174.1 132.2 113.0 Operating expenses: Operation and maintenance 145.6 105.8 87.8 Depreciation, depletion and amortization 11.0 7.0 6.2 Taxes, other than income 2.9 3.3 4.5 159.5 116.1 98.5 Operating income $ 14.6 $ 16.1 $ 14.5 Sales (000's): Aggregates (tons) 5,113 3,374 2,904 Asphalt (tons) 758 694 373 Ready-mixed concrete (cubic yards) 516 340 307 Coal (tons) 2,375 2,899 4,218 *** Prior to August 1, 1997, financial results did not include information related to Knife River's ownership interest in Hawaiian Cement, 50 percent of which was acquired in September 1995, and was accounted for under the equity method. On July 31, 1997, Knife River acquired the 50 percent interest in Hawaiian Cement that it did not previously own, and subsequent to that date financial results are consolidated into Knife River's financial statements. Oil and Natural Gas Production Operations Years ended December 31, 1997 1996 1995 Operating revenues: Oil $ 36.6 $ 39.0 $ 30.1 Natural gas 31.8 29.3 18.7 68.4 68.3 48.8 Operating expenses: Operation and maintenance 15.8 15.6 13.7 Depreciation, depletion and amortization 24.4 25.0 18.6 Taxes, other than income 3.9 3.5 2.6 44.1 44.1 34.9 Operating income $ 24.3 $ 24.2 $ 13.9 Production (000's): Oil (barrels) 2,088 2,149 1,973 Natural gas (Mcf) 13,192 14,067 12,319 Average sales price: Oil (per barrel) $ 17.50 $ 17.91 $ 15.07 Natural gas (per Mcf) 2.41 2.09 1.51 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 $49.6 million, $48.0 million and $1.6 million, respectively, for 1997, $58.2 million, $53.8 million and $4.4 million, respectively, for 1996, and $54.6 million, $49.2 million and $5.4 million, respectively, for 1995. 1997 compared to 1996 Electric Operations Operating income at the electric business increased primarily due to increased retail sales and sales for resale revenues. Retail sales revenue increased due to increased rates in Wyoming reflecting recovery of costs associated with the new power supply contract with Black Hills Power and Light Company beginning January 1, 1997. Higher average realized rates in the remaining service territory and decreased net refunding due to timing of fuel costs to customers also added to the retail sales revenue improvement. Decreased weather-related sales primarily to residential customers in the fourth quarter somewhat offset the increase in retail sales revenue. Sales for resale revenue increased due to higher average realized rates caused by favorable market conditions in the third and fourth quarters. Increases in utility services revenue and related increases in operation and maintenance expense, depreciation, depletion, and amortization and taxes other than income resulted from International Line Builders, Inc. and High Line Equipment, Inc., which were acquired on July 1, 1997. Exclusive of the above- mentioned acquisitions, operation expenses decreased due to lower payroll and benefit-related expenses, which also added to the operating income improvement. Increased maintenance expense partially offset the increase in operating income. Power generation maintenance expense increased due to $1.9 million in costs resulting from a ten-week maintenance outage at the Coyote Station in 1997; this was somewhat offset by 1996 costs resulting from maintenance work at both the Lewis and Clark Station and the Big Stone Station. Higher transmission and distribution maintenance expense, due to the repair of damages associated with the April 1997 blizzard, also added to the increase in maintenance expense. Increased fuel and purchased power costs, largely resulting from increased purchase power demand charges and changes in generation mix, partially offset the operating income increase. The increase in demand charges is related to the power supply contract with Black Hills Power and Light Company. Earnings for the electric business improved due to the operating income increase but were slightly offset by increased interest expense due to higher average short-term debt balances. Earnings attributable to the electric services companies acquired on July 1, 1997, were $947,000. Natural Gas Distribution Operations Operating income decreased at the natural gas distribution business as a result of reduced sales of 3.9 million decatherms, the result of 15% warmer weather. The pass through of higher average gas costs more than offset the revenue decline that resulted from the reduced sales volumes. A general rate increase placed into effect in Montana in May 1996, which added to the revenue improvement, partially offset the operating income decline. Decreased operations expense due to lower payroll and benefit- related costs also partially offset the decrease in operating income. The effects of higher volumes transported, primarily to large industrial customers, were offset by lower average transportation rates. Natural gas distribution earnings declined largely due to the decrease in operating income. Decreased net interest expense and increased return on gas in storage and prepaid demand balances (included in Other income -- net) slightly offset the earnings decline. The decrease in net interest expense resulted from reduced carrying costs on natural gas costs refundable through rate adjustments due to lower refundable balances. Natural Gas Transmission Operations Operating income at the natural gas transmission business decreased primarily due to a decline in transportation revenues. Transportation revenues were lower due to the reversal of certain reserves for regulatory contingencies which added $4.2 million ($2.6 million after tax) to revenue in 1996. In addition, reduced recovery of deferred natural gas contract buy-out/buy-down and gas supply realignment costs and lower average transportation rates contributed to the decrease in transportation revenue. Transportation revenues also decreased due to additional reserved revenues provided, with a corresponding reduction in depreciation expense, as a result of FERC orders relating to a 1992 general rate proceeding. Increased volumes transported to off-system markets, due to sales of natural gas held under the repurchase commitment, were partially offset by lower on-system transportation, somewhat reducing the transportation revenue decline. Sales of natural gas held under the repurchase commitment were 17.9 MMdk, primarily volumes sold to off-system markets and volumes sold in place. Taxes other than income increased due primarily to increased property and production taxes which also contributed to the operating income decline. Natural gas production revenues for 1997, excluding the effect of intercompany eliminations of $5.6 million, improved as a result of both higher volumes produced and increased prices which partially offset the decrease in operating income. The increases in energy marketing revenue, purchased gas sold and the related increase in operation and maintenance expense resulted from Prairielands becoming a wholly owned subsidiary effective January 1, 1997. Operation expenses, excluding Prairielands, decreased due to reduced amortization of deferred natural gas contract buy-out/buy- down and gas supply realignment costs offset in part by higher royalties due to both a royalty settlement with the United States Minerals Management Service and increased production and prices. Earnings for this business increased due to the September 1996 $21.1 million ($12.9 million after tax) write-down of the natural gas available under the repurchase commitment to the then current market price. Gains realized on the sale of natural gas held under the repurchase commitment and decreased carrying costs on this gas stemming from lower average borrowings also added to the earnings increase. Increased income taxes due to the reversal of certain income tax reserves aggregating $4.8 million in September 1996 and decreased operating income both partially offset the earnings improvement. Construction Materials and Mining Operations Construction Materials Operations -- Construction materials operating income increased $3.3 million due to higher revenues primarily resulting from the acquisitions of Baldwin in April 1996, Medford Ready Mix, Inc. (Medford) in June 1996, Orland Asphalt in February 1997, and the 50% interest in Hawaiian Cement that Knife River did not previously own in July 1997. Revenues at other construction materials operations increased as a result of higher aggregate and ready-mixed concrete sales volumes, increased construction revenues, and higher asphalt prices. The increase in operation and maintenance and depreciation expenses was largely due to expenses associated with such acquisitions. Operation and maintenance expenses also increased at the other construction materials operations due to higher aggregate and ready- mixed concrete volumes sold. Coal Operations -- Operating income for the coal operations decreased $4.8 million, largely due to decreased revenues resulting from lower sales of 524,000 tons to the Coyote Station, the result of the ten-week maintenance outage. Higher average sales prices at the Beulah Mine partially offset the reduced coal revenues. Increased operation and maintenance expense due to higher stripping costs at the Beulah Mine, partially offset by lower volume-related costs and decreased taxes other than income, also added to the operating income decline. Consolidated -- Earnings declined due to decreased operating income at the coal business and decreased Other income -- net. The decrease in Other income -- net was due to the purchase of the 50% interest in Hawaiian Cement that Knife River did not previously own. Prior to August 1997, Knife River's original 50 percent ownership interest in Hawaiian Cement was accounted for under the equity method. However, on July 31, 1997, Knife River acquired the 50 percent interest in Hawaiian Cement that it did not previously own and Knife River in August 1997 began consolidating Hawaiian Cement into its financial statements. In addition, higher interest expense resulting mainly from increased long-term debt due to the aforementioned acquisitions also added to the decrease in earnings. Increased construction materials operating income and gains realized from the sale of equipment, partially offset the earnings decline. Oil and Natural Gas Production Operations Operating income for the oil and natural gas production business at Fidelity Oil increased slightly as a result of higher natural gas revenues. The increase in natural gas revenue resulted from a $4.6 million improvement due to higher average prices somewhat offset by a $2.1 million decrease due to lower production. Decreased oil revenue largely offset the natural gas revenue increase. The decline in oil revenue was due to a $1.3 million decrease resulting from lower average oil prices and a $1.1 million decline due to lower production. Decreased depreciation, depletion and amortization, largely the result of lower production, also added to the increase in operating income. Increased taxes other than income partially offset the increase in operating income. Earnings for this business unit increased due to the operating income improvement and decreased interest expense due to lower average long-term debt balances. Increased income taxes somewhat offset the earnings improvement. The increase in income taxes resulted from the reversal of certain tax reserves aggregating $1.8 million in September 1996 somewhat offset by higher tax credits in 1997. 1996 compared to 1995 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, was 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 brought 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 of 1996, 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. 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 of which closed in September 1995, and one of which experienced lower production, and to a cement manufacturing facility due to its use of an 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. 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. 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 a 50 percent interest in Hawaiian Cement acquired in September 1995 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. 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. 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 effect 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, and compliance with the year 2000 issue as discussed later. Year 2000 Compliance The year 2000 issue is the result of computer programs having been written using two digits rather than four digits to define the applicable year. The Company has recently completed an assessment of its operations to determine the costs expected to be incurred specifically related to modifications necessary for year 2000 compatibility. While the Company will continue to evaluate the potential effects of the year 2000 issue, based on its recent assessment, the Company believes that these costs will not be material to its results of operations. The Company's operations with respect to the year 2000 issue may also be affected by other entities with which the Company transacts business. The Company is currently unable to determine the potential adverse consequences, if any, that could result from such entities' failure to effectively address this issue. Liquidity and Capital Commitments The Company's net capital expenditures (in millions of dollars) for 1995 through 1997 and as anticipated for 1998 through 2000 are summarized in the following table, which also includes the Company's capital needs for the retirement of maturing long-term securities. Actual Estimated* 1995 1996 1997 Capital Expenditures -- 1998 1999 2000 Montana-Dakota: $ 19.7 $ 18.7 $ 18.4 Electric $ 17.0 $ 15.9 $ 17.0 8.9 6.3 8.8 Natural Gas Distribution 7.9 9.4 7.5 28.6 25.0 27.2 24.9 25.3 24.5 12.3 10.9 11.4 Williston Basin 21.4 26.9 20.0 36.8 25.0 41.5 Knife River 27.8 11.6 10.1 39.9 51.8 30.6 Fidelity 50.0 62.0 62.0 --- --- 11.4 Other 2.8 1.1 1.1 117.6 112.7 122.1 126.9 126.9 117.7 Net proceeds from sale or (2.8) (11.8) (4.5) disposition of property .5 (1.5) (1.6) 114.8 100.9 117.6 Net capital expenditures 127.4 125.4 116.1 Retirement of Long-term Debt/Preferred Stock -- 10.4 35.4 42.4 Montana-Dakota 5.4 5.4 5.4 10.1 8.0 .5 Williston Basin .5 .5 .8 --- --- --- Knife River 1.3 1.3 36.8 --- --- 4.8 Fidelity --- 7.9 10.8 --- --- .3 Other .7 .2 .1 20.5 43.4 48.0 7.9 15.3 53.9 $135.3 $144.3 $165.6 Total $135.3 $140.7 $170.0 * The anticipated 1998 through 2000 net capital expenditures reflected in the above table do not include potential acquisitions. To the extent that acquisitions occur, such acquisitions would be financed with existing credit facilities and the issuance of long-term debt and the Company's equity securities. In reconciling total net capital expenditures to investing activities per the Consolidated Statements of Cash Flows, the net capital expenditures for Prairielands of $800,000 and $2.6 million in 1996 and 1995, respectively, included with Williston Basin above and not considered a major business segment, are not reflected in investing activities in the Consolidated Statements of Cash Flows. In addition, the total 1997 net capital expenditures, related to acquisitions, in the above table include assumed debt and the issuance of the Company's equity securities, which were $9.9 million in total. In 1997 Montana-Dakota provided all the funds needed for its net capital expenditures and securities retirements, excluding the $20 million discussed below, from internal sources. Net capital expenditures for the years 1998 through 2000 include those for system upgrades, routine replacements and service extensions. Montana-Dakota expects to provide all of the funds required for these net capital expenditures and securities retirements for the years 1998 through 2000 from internal sources, through the use of the Company's $40 million revolving credit and term loan agreement, $18 million of which was outstanding at December 31, 1997, 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 October 1997, the Company redeemed $20 million of its 9 1/8% Series first mortgage bonds, due October 1, 2016. The funds required to retire the 9 1/8% Series first mortgage bonds were provided by the issuance of $30 million in Secured Medium-Term Notes on September 30, 1997. In addition, in November 1997, the Company redeemed $5 million of its 9 1/8% Series first mortgage bonds, due May 15, 2006. On December 19, 1997, amounts available under the revolving credit and term loan agreement increased from $30 million to $40 million. Williston Basin's 1997 net capital expenditures and securities retirements were met through internally generated funds. Williston Basin's net capital expenditures for the years 1998 through 2000, excluding potential acquisitions, include those for pipeline expansion projects, routine system improvements and continued development of natural gas reserves. These expenditures are expected to be met with a combination of internally generated funds, short-term lines of credit aggregating $40.6 million, $350,000 of which was outstanding at December 31, 1997, 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. Knife River's 1997 net capital expenditures including the acquisitions of Orland Asphalt and the 50 percent interest in Hawaiian Cement that it did not previously own were met through funds generated from internal sources and a revolving credit agreement. Knife River's 1998 through 2000 net capital expenditures, excluding potential acquisitions, include routine equipment rebuilding and replacement and the construction of aggregate materials handling facilities. It is anticipated that funds generated from internal sources, short-term lines of credit aggregating $26 million, $2 million of which was outstanding at December 31, 1997, a revolving credit agreement of $85 million, $33 million of which was outstanding at December 31, 1997, and the issuance of long-term debt and the Company's equity securities will meet the needs of this business unit for 1998 through 2000. In June 1997, amounts available under the revolving credit agreement were increased from $55 million to $85 million. In addition, in July 1997, amounts available under the short-term lines of credit increased from $11 million to $26 million. In November 1997, Knife River privately placed $35 million of notes with the proceeds used to replace other long-term debt. Fidelity Oil's 1997 net capital expenditures related to its oil and natural gas acquisition, development and exploration program were met through funds generated from internal sources. Fidelity's borrowing base, which is based on total proved reserves, is currently $65 million. This consists of $20 million of issued notes, $10 million in an uncommitted note shelf facility, and a $35 million revolving line of credit, $13 million of which was outstanding at December 31, 1997. It is anticipated that Fidelity's 1998 through 2000 net capital expenditures and debt retirements will be met from internal sources and existing long-term credit facilities. Fidelity's net capital expenditures for 1998 through 2000 will be used to further enhance production and reserve growth. Other corporate 1997 net capital expenditures, largely those expended for the acquisitions of International Line Builders, Inc. and High Line Equipment, Inc., were met through short-term lines of credit and the issuance of long-term debt and the Company's equity securities. It is anticipated that 1998 through 2000 other net capital expenditures, excluding potential acquisitions, used for routine equipment maintenance and replacements will be met from internal sources and existing short-term lines of credit aggregating $3.8 million, $997,000 of which was outstanding at December 31, 1997. The Company utilizes its short-term lines of credit aggregating $50 million, none of which was outstanding on December 31, 1997, and its $40 million revolving credit and term loan agreement, $18 million of which was outstanding at December 31, 1997, as previously described, to meet its short-term financing needs and to take advantage of market conditions when timing the placement of long- term or permanent financing. On July 31, 1997, amounts available under the short-term lines of credit were increased from $40 million to $50 million. 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, 1997, the Company could have issued approximately $259 million of additional first mortgage bonds. The Company's coverage of fixed charges including preferred dividends was 3.4 and 2.7 times for 1997 and 1996, respectively. Additionally, the Company's first mortgage bond interest coverage was 6.0 times in 1997 compared to 5.4 times in 1996. Common stockholders' equity as a percent of total capitalization was 55 percent and 54 percent at December 31, 1997 and 1996, respectively. Recent Development On March 5, 1998, the Company acquired Morse Bros., Inc. (MBI), and S2 - F Corp. (S2-F), privately-held construction materials companies located in Oregon's Willamette Valley. The purchase consideration for such companies consisted of approximately $96 million of the Company's common stock and cash, the assumption of certain liabilities and an adjustment based on working capital. The common stock of the Company, issued in exchange for all of the issued and outstanding stock of MBI and S2-F was unregistered and is subject to certain restrictions. The acquisition will be accounted for under the purchase method of accounting. Under this method, the consideration for the stock of MBI and S2-F will be allocated to the underlying assets acquired and liabilities assumed, based on their estimated fair market values. The Company anticipates that the effect of such acquisitions will be accretive to earnings. Financial statements of the acquired companies and proforma financial statements have not been presented as such information is not required in accordance with the rules and regulations of the Securities and Exchange Commission. MBI, the largest construction materials supplier in Oregon, sells aggregate, ready-mixed concrete, asphaltic concrete, prestress concrete and construction services in the Willamette Valley from Portland to Eugene. The products of MBI are used in the construction of streets, roads, and highways and in both building and bridge structures. Assets owned by MBI include aggregate reserves and construction materials plant and equipment. S2-F sells aggregate and construction services and their properties consist primarily of construction and aggregate mining equipment and leased aggregate reserves. In 1997, MBI and S2-F had combined net sales of $107 million and have approximately 370 million tons of aggregate reserves, of which 270 million tons are permitted. It is the intent of the Company that MBI and S2-F continue their operations and businesses. Effects of Inflation Inflation did not have a significant effect on the Company's operations in 1997, 1996 or 1995. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Not required for fiscal 1997 because the Company's market capitalization was less than $2.5 billion as of January 28, 1997. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Reference is made to Pages 25 through 49 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 2 through 6 and 12 and 13 of the Company's Proxy Statement dated March 9, 1998 (Proxy Statement) which is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION Reference is made to Pages 7 through 12 of the Proxy Statement. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Reference is made to Page 14 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, 1997 * Consolidated Balance Sheets at December 31, 1997 and 1996 * Consolidated Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 1997 * Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1997 * 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 1997 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 1997 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, filed as Exhibit 10 (a) to Form 10-K for the year ended December 31, 1996, in File No. 1-3480 * + 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, filed as Exhibit 10 (d) to Form 10-K for the year ended December 31, 1996, in File No. 1-3480 * + 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 * + 10(h) Non-Employee Director Long-Term Incentive Plan, filed as Exhibit 10 (h) to Form 10-Q for the quarterly period ended June 30, 1997, in File No. 1-3480 * + 10(i) Executive Long-Term Incentive Plan, filed as Exhibit 10 (i) to Form 10-Q for the quarterly period ended June 30, 1997, in File No. 1-3480 * 12 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends ** 13 Selected financial data, financial statements and supplementary data as contained in the Annual Report to Stockholders for 1997 ** 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: March 6, 1998 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 March 6, 1998 Harold J. Mellen, Jr. Officer (President and Chief Executive Officer) and Director /s/ Douglas C. Kane Chief March 6, 1998 Douglas C. Kane (Executive Vice President, Administrative & Chief Administrative & Corporate Corporate Development Officer) Development Officer and Director /s/ Warren L. Robinson Chief Financial March 6, 1998 Warren L. Robinson (Vice President, Officer Treasurer and Chief Financial Officer) /s/ Vernon A. Raile Chief Accounting March 6, 1998 Vernon A. Raile (Vice President, Officer Controller and Chief Accounting Officer) /s/ John A. Schuchart Director March 6, 1998 John A. Schuchart (Chairman of the Board) /s/ San W. Orr, Jr. Director March 6, 1998 San W. Orr, Jr. (Vice Chairman of the Board) /s/ Thomas Everist Director March 6, 1998 Thomas Everist /s/ Richard L. Muus Director March 6, 1998 Richard L. Muus /s/ Robert L. Nance Director March 6, 1998 Robert L. Nance /s/ John L. Olson Director March 6, 1998 John L. Olson /s/ Harry J. Pearce Director March 6, 1998 Harry J. Pearce /s/ Homer A. Scott, Jr. Director March 6, 1998 Homer A. Scott, Jr. /s/ Joseph T. Simmons Director March 6, 1998 Joseph T. Simmons /s/ Sister Thomas Welder Director March 6, 1998 Sister Thomas Welder EXHIBIT INDEX Exhibit No. 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, filed as Exhibit 10 (a) to Form 10-K for the year ended December 31, 1996, in File No. 1-3480 * + 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, filed as Exhibit 10 (d) to Form 10-K for the year ended December 31, 1996, in File No. 1-3480 * + 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 * + 10(h) Non-Employee Director Long-Term Incentive Plan, filed as Exhibit 10 (h) to Form 10-Q for the quarterly period ended June 30, 1997, in File No. 1-3480 * + 10(i) Executive Long-Term Incentive Plan, filed as Exhibit 10 (i) to Form 10-Q for the quarterly period ended June 30, 1997, in File No. 1-3480 * 12 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends ** 13 Selected financial data, financial statements and supplementary data as contained in the Annual Report to Stockholders for 1997 ** 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. EX-3.B 2 BYLAWS 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 execute 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 such person 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 such person in connection with such action, suit or proceeding if such person acted in good faith and in a manner such person 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 such person's 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 such person 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 such person's 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 such person 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 such person in connection with the defense or settlement of such action or suit if such person acted in good faith and in a manner such person 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 of all 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 present or former 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, such person shall be indemnified against expenses (including attorneys' fees) actually and reasonably incurred by such person in connection therewith. (d) Any indemnification under subsections (a) and (b) 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 present or former director, officer, employee or agent is proper in the circumstances because such person has met the applicable standard of conduct as set forth in subsections (a) and (b) of this Section. Such determination shall be made (1) by a majority vote of the directors who are not parties to such action, suit or proceeding, even though less than a quorum, or (2) by a committee of such directors designated by majority vote of such directors, even though less than a quorum, or (3) if there are no such directors, or if such directors so direct, by independent legal counsel in a written opinion, or (4) by the stockholders. (e) Expenses (including attorneys' fees) incurred by a present or former 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 such person 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 such person's 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 such person and incurred by such person in any such capacity, or arising out of such person's status as such, whether or not the Corporation would have the power to indemnify such person 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 such person would if such person 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 such person 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-12 3 RATIO OF EARNINGS TO FIXED CHARGES MDU RESOURCES GROUP, INC. COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS Years Ended December 31, 1997 1996 1995 1994 1993 (In thousands of dollars) Earnings Available for Fixed Charges: Net Income per Consolidated Statements of Income $ 54,617 $ 45,470 $ 41,633 $ 39,845 $ 38,817* Income Taxes 30,743 16,087 23,057 18,833 19,982* 85,360 61,557 64,690 58,678 58,799 Rents (a) 1,249 1,031 894 878 871 Interest (b) 33,047 34,101 29,924 29,173 27,928 Total Earnings Available for Fixed Charges $119,656 $ 96,689 $ 95,508 $ 88,729 $ 87,598* Preferred Dividend Requirements $ 782 $ 787 $ 792 $ 797 $ 802 Ratio of Income Before Income Taxes to Net Income 156% 135% 155% 147% 151% Preferred Dividend Factor on Pretax Basis 1,220 1,062 1,228 1,172 1,211 Fixed Charges (c) 34,296 35,132 30,818 30,051 28,799 Combined Fixed Charges and Preferred Stock Dividends $ 35,516 $ 36,194 $ 32,046 $ 31,223 $ 30,010 Ratio of Earnings to Fixed Charges 3.49x 2.75x 3.10x 2.95x 3.04x* Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends 3.37x 2.67x 2.98x 2.84x 2.92x* * 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 4 1997 ANNUAL REPORT MDU RESOURCES GROUP, INC. 1997 FINANCIAL REPORT REPORT OF MANAGEMENT The management of MDU Resources 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, effective 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, 1997 1996 1995 (In thousands, except per share amounts) Operating Revenues Electric $164,351 $138,761 $134,609 Natural gas 200,789 175,408 167,787 Construction materials and mining 174,147 132,222 113,066 Oil and natural gas production 68,387 68,310 48,784 607,674 514,701 464,246 Operating Expenses Fuel and purchased power 45,604 43,983 41,769 Purchased natural gas sold 77,082 48,886 53,351 Operation and maintenance 283,894 225,682 202,327 Depreciation, depletion and amortization 65,767 62,651 54,825 Taxes, other than income 23,766 21,974 21,398 496,113 403,176 373,670 Operating Income Electric 33,089 29,476 29,898 Natural gas distribution 10,410 11,504 6,917 Natural gas transmission 29,169 30,231 25,427 Construction materials and mining 14,602 16,062 14,463 Oil and natural gas production 24,291 24,252 13,871 111,561 111,525 90,576 Other income -- net 4,008 5,617 4,789 Interest expense 30,209 28,832 24,690 Costs on natural gas repurchase commitment (Note 3) --- 26,753 5,985 Income before income taxes 85,360 61,557 64,690 Income taxes 30,743 16,087 23,057 Net income 54,617 45,470 41,633 Dividends on preferred stocks 782 787 792 Earnings on common stock $53,835 $44,683 $40,841 Earnings per common share--basic $1.86 $1.57 $1.43 Earnings per common share--diluted $1.86 $1.57 $1.43 Dividends per common share $1.13 $1.10 $1.0782 The accompanying notes are an integral part of these consolidated statements. CONSOLIDATED BALANCE SHEETS MDU RESOURCES GROUP, INC. December 31, 1997 1996 (In thousands) ASSETS Current Assets Cash and cash equivalents $ 28,174 $ 47,799 Receivables 80,585 73,187 Inventories 41,322 27,361 Deferred income taxes 17,356 26,011 Prepayments and other current assets 12,479 17,300 179,916 191,658 Investments (Note 15) 18,935 53,501 Property, Plant and Equipment Electric 566,247 546,477 Natural gas distribution 172,086 164,843 Natural gas transmission 288,709 273,775 Construction materials and mining 243,110 173,663 Oil and natural gas production 240,193 211,555 1,510,345 1,370,313 Less accumulated depreciation, depletion and amortization 670,809 617,724 839,536 752,589 Deferred charges and other assets 75,505 91,425 $1,113,892 $1,089,173 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Short-term borrowings $ 3,347 $ 3,950 Long-term debt and preferred stock due within one year 7,902 11,854 Accounts payable 31,571 31,580 Taxes payable 9,057 8,683 Dividends payable 8,574 8,099 Other accrued liabilities, including reserved revenues 88,563 100,938 149,014 165,104 Long-term debt (Note 11) 298,561 280,666 Deferred credits and other liabilities Deferred income taxes 119,747 116,208 Other liabilities (Note 3) 143,574 159,721 263,321 275,929 Commitments and contingencies (Notes 2, 3, 4 and 14) Stockholders' Equity Preferred stocks (Note 10) 16,700 16,800 Common stockholders' equity Common stock (Note 9) Authorized -- 75,000,000 shares, $3.33 par value Outstanding -- 29,143,332 and 28,476,981 shares in 1997 and 1996, respectively 97,047 94,828 Other paid-in capital 76,526 64,305 Retained earnings 212,723 191,541 Total common stockholders' equity 386,296 350,674 Total stockholders' equity 402,996 367,474 $1,113,892 $1,089,173 The accompanying notes are an integral part of these consolidated statements. CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY MDU RESOURCES GROUP, INC. Years ended Other December 31, Common Stock Paid-In Retained 1997, 1996 and 1995 Shares Amount Capital Earnings Total (In thousands, except shares) Balance at December 31, 1994 18,984,654 $63,219 $95,914 $168,050 $327,183 Net income --- --- --- 41,633 41,633 Dividends on preferred stocks --- --- --- (792) (792) Dividends on common stock --- --- --- (30,707) (30,707) Three-for-two common stock split (Note 9) 9,492,327 31,609 (31,609) --- --- Balance at December 31, 1995 28,476,981 94,828 64,305 178,184 337,317 Net income --- --- --- 45,470 45,470 Dividends on preferred stocks --- --- --- (787) (787) Dividends on common stock --- --- --- (31,326) (31,326) Balance at December 31, 1996 28,476,981 94,828 64,305 191,541 350,674 Net income --- --- --- 54,617 54,617 Dividends on preferred stocks --- --- --- (782) (782) Dividends on common stock --- --- --- (32,653) (32,653) Issuance of common stock: Acquisitions 225,629 751 3,622 --- 4,373 Other 440,722 1,468 8,599 --- 10,067 Balance at December 31, 1997 29,143,332 $97,047 $76,526 $212,723 $386,296 The accompanying notes are an integral part of these consolidated statements. CONSOLIDATED STATEMENTS OF CASH FLOWS MDU RESOURCES GROUP, INC. Years ended December 31, 1997 1996 1995 (In thousands) Operating Activities Net income $ 54,617 $ 45,470 $ 41,633 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 65,767 62,651 54,825 Deferred income taxes and investment tax credit -- net 7,152 4,551 7,631 Recovery of deferred natural gas contract litigation settlement costs, net of income taxes 3,360 6,580 7,177 Write-down of natural gas available under repurchase commitment, net of income taxes (Note 3) --- 11,364 --- Changes in current assets and liabilities: Receivables 6,951 (9,346) (6,552) Inventories (4,214) (1,218) 3,141 Other current assets 10,681 4,185 (3,943) Accounts payable (5,605) 7,584 2,039 Other current liabilities (6,087) (22,434) 17,177 Other noncurrent changes 6,007 (3,149) (1,023) Net cash provided by operating activities 138,629 106,238 122,105 Financing Activities Net change in short-term borrowings (5,919) 3,350 (80) Issuance of long-term debt 54,064 81,300 36,710 Repayment of long-term debt (47,899) (43,262) (20,433) Retirement of preferred stocks (100) (100) (100) Issuance of common stock 10,067 --- --- Retirement of natural gas repurchase commitment (52,090) (4,157) (204) Dividends paid (33,435) (32,113) (31,499) Net cash provided by (used in) financing activities (75,312) 5,018 (15,606) Investing Activities Capital expenditures including acquisitions of businesses: Electric (18,713) (18,674) (19,689) Natural gas distribution (8,858) (6,255) (8,878) Natural gas transmission (13,205) (10,127) (9,688) Construction materials and mining (40,797) (25,063) (36,810) Oil and natural gas production (30,651) (51,821) (39,917) (112,224) (111,940) (114,982) Net proceeds from sale or disposition of property 4,522 11,803 2,802 Net capital expenditures (107,702) (100,137) (112,180) Sale of natural gas available under repurchase commitment 27,008 10,595 163 Investments (2,248) (7,313) 1,726 Net cash used in investing activities (82,942) (96,855) (110,291) Increase (decrease) in cash and cash equivalents (19,625) 14,401 (3,792) Cash and cash equivalents -- beginning of year 47,799 33,398 37,190 Cash and cash equivalents -- end of year $ 28,174 $ 47,799 $ 33,398 The accompanying notes are an integral part of these consolidated statements. NOTE 1 Summary of Significant 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 1997, 1996 and 1995. 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. 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 and is reflected on the company's Consolidated Balance Sheets in "Deferred charges and other assets". See Note 3 for discussion on the write-down which occurred in 1996 of the natural gas available under the repurchase commitment with Frontier. Inventories Inventories, other than natural gas in underground storage, consist primarily of materials and supplies and inventories 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. For its construction business, the company recognizes revenue 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 liabilities" 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. Earnings per Common Share In 1997, the company adopted SFAS No. 128, "Earnings Per Share". The adoption of this pronouncement did not affect previously reported earnings per common share. Basic earnings per common share were computed by dividing earnings on common stock by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the year, plus the effect of outstanding stock options. The weighted average common shares outstanding used for basic earnings per common share (in thousands) were 28,877 in 1997 and 28,477 in both 1996 and 1995. The number of common shares used for diluted earnings per common share (in thousands) were 28,985 in 1997, 28,549 in 1996 and 28,526 in 1995. 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, 1997 1996 1995 (In thousands) Interest, net of amount capitalized $25,626 $25,449 $24,436 Income taxes $18,171 $28,163 $18,330 The company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The company's Consolidated Statements of Cash Flows include the effects from acquisitions. Reclassifications Certain reclassifications have been made in the financial statements for prior years to conform to the current presentation. Such reclassifications had no effect on net income or common stockholders' equity as previously reported. 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. On October 20, 1997, Williston Basin appealed to the U.S. District Court of Appeals for the D.C. Circuit (D.C. Circuit Court) certain issues decided by the FERC in prior orders concerning the 1992 proceeding. On December 10, 1997, the FERC issued an order accepting, subject to certain conditions, Williston Basin's July 25, 1997 compliance filing. On December 22, 1997, Williston Basin submitted a compliance filing pursuant to the FERC's December 10, 1997 order. On December 31, 1997, Williston Basin refunded $33.8 million to its customers, including $30.8 million to Montana-Dakota, in addition to the $6.1 million interim refund that it had previously made in November 1996. All such amounts had been previously reserved. Williston Basin is awaiting an order from the FERC on its December 22, 1997 compliance filing. Reserves have been provided for a portion of the revenues that have been collected subject to refund with respect to pending regulatory proceedings and 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, 1997, borrowings totaled $32.0 million at a weighted average interest rate of 6.63 percent. At December 31, 1997 and 1996, the natural gas repurchase commitment of $30.4 million and $66.3 million, respectively, is reflected on the company's Consolidated Balance Sheets under "Other liabilities" and $1.6 million and $17.7 million, respectively, is reflected under "Other accrued liabilities". 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 which in December 1996 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 as to the appropriate costs to be allocated. Williston Basin sells and transports natural gas held under the repurchase commitment. 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 43.0 MMdk of this gas to its then current 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. At December 31, 1997 and 1996, natural gas held under the repurchase commitment of $14.6 million and $37.2 million, respectively, is included in the company's Consolidated Balance Sheets under "Deferred charges and other assets". The recognition of the then current market value of this natural gas facilitated the sale by Williston Basin of 28.1 MMdk from the date of this write-down through December 31, 1997, and should allow Williston Basin to market the remaining 14.9 MMdk on a sustained basis enabling Williston Basin to liquidate this asset over approximately the next three to four 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 totaled approximately $19 million or, under its alternative pricing theory, approximately $39 million. On June 26, 1997, the Federal District Court issued its order awarding Moncrief damages of approximately $15.6 million. On July 25, 1997, the Federal District Court issued an order limiting Moncrief's reimbursable costs to post-judgment interest, instead of both pre- and post-judgment interest as Moncrief had sought. On August 25, 1997, Moncrief filed a notice of appeal with the United States Court of Appeals for the Tenth Circuit related to the Federal District Court's orders. On September 2, 1997, Williston Basin and the company filed a notice of cross-appeal. Williston Basin believes that it is entitled to recover from ratepayers virtually all of the costs ultimately incurred as a result of these orders as gas supply realignment transition costs pursuant to the provisions of the FERC's Order 636. However, the amount of costs that can ultimately be recovered is subject to approval by the FERC and market conditions. In December 1993, Apache Corporation (Apache) and Snyder Oil Corporation (Snyder) filed suit in North Dakota Northwest Judicial District Court (North Dakota District Court), against Williston Basin and the company. Apache and Snyder are oil and natural gas producers which 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 as Williston Basin, the company and Koch have settled their disputes. Apache and Snyder have recently provided alleged damages under differing theories ranging up to $4.8 million without interest. A motion to intervene in the case by several other producers, all of which had contracts with Koch but not with Williston Basin, was denied in December 1996. The trial before the North Dakota District Court was completed on November 6, 1997. Williston Basin and the company are awaiting a decision from the North Dakota District Court. In a related matter, on March 14, 1997, a suit was filed by nine other producers, several of which had unsuccessfully tried to intervene in the Apache and Snyder litigation, against Koch, Williston Basin and the company. The parties to this suit are making claims similar to those in the Apache and Snyder litigation, although no specific damages have been specified. In Williston Basin's opinion, the claims of Apache and Snyder are without merit and overstated and the claims of the nine other producers are without merit. If any amounts are ultimately found to be due, Williston Basin plans to file with the FERC for recovery from ratepayers. 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 have 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 that 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 the Co-owners are seeking damages in an unspecified amount. In January 1996, the company and Knife River filed separate motions with the State District Court to dismiss or stay, pending arbitration. In May 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. In September 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. By order dated April 25, 1997, the arbitration panel concluded that the claims raised by the Co-owners are arbitrable. The Co-owners have 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, of 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. By letter dated May 14, 1997, Knife River requested permission to move for summary judgment which permission was granted by the arbitration panel over objections of the Co-owners. Knife River filed its summary judgment motion on July 21, 1997, which motion was denied on October 29, 1997. 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. and Unitek Solvent 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 U.S. 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 U.S. 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 award of punitive damages. Hawaiian Cement is a Hawaiian general partnership whose general partners are now Knife River Hawaii, Inc. and Knife River Dakota, Inc., indirect wholly owned subsidiaries of the company. Knife River Dakota, Inc. purchased its partnership interest from Adelaide Brighton Cement (Hawaii), Inc. on July 31, 1997. Unitek sought civil penalties under the Clean Air Act (as described below), and up to $20 million in damages for various claims (as described above). In August 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. In September 1996, Unitek and Hawaiian Cement reached a settlement which resolved all claims except as to Clean Air Act penalties. 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 continued to negotiate the remaining Clean Air Act claims. In May 1996, the EPA issued a Notice of Violation (NOV) to Hawaiian Cement. The NOV stated 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. On April 7, 1997, a settlement resolving the remaining Clean Air Act claims and the EPA's NOV issued in May 1996, was reached by Hawaiian Cement, the EPA and Unitek. This settlement is subject to public comment and the approval of the District Court. If the District Court approves the April 1997 settlement, the total costs relating to both the September 1996 and April 1997 settlements are not expected to 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, 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 $43.1 million at December 31, 1997, and $42.3 million at December 31, 1996. In addition, $11.4 million and $7.2 million at December 31, 1997 and 1996, 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: 1997 1996 (In thousands) Regulatory assets: Natural gas contract settlement and restructuring costs $ --- $ 4,960 Long-term debt refinancing costs 11,466 13,520 Postretirement benefit costs 2,940 3,849 Plant costs 3,173 3,341 Other 10,899 7,890 Total regulatory assets 28,478 33,560 Regulatory liabilities: Reserves for regulatory matters 39,193 59,277 Natural gas costs refundable through rate adjustments 21,721 1,499 Taxes refundable to customers 13,933 12,868 Plant decommissioning costs 5,843 5,301 Other 1,393 2,433 Total regulatory liabilities 82,083 81,378 Net regulatory position $(53,605) $(47,818) As of December 31, 1997, 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 19 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 the 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: Years ended December 31, 1997 1996 1995 (Notional amounts in thousands) Oil swap/collar agreements:* Range of fixed prices per barrel $19.77-$21.36 $18.74-$19.07 $17.75-$20.75 Notional amount (in barrels) 730 635 260 Natural gas swap/collar agreements:* Range of fixed prices per MMBtu $1.30-$2.395 $1.40-$2.05 $1.70-$1.85 Notional amount (in MMBtu's) 8,039 5,331 644 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% 5.50%-6.50% 5.97% Notional amount (in dollars) $30,000 $30,000 $20,000 * Receive fixed -- pay variable ** Receive variable -- pay fixed The following table summarizes swap agreements outstanding at December 31, 1997 (notional amounts in thousands): Notional Fixed Price Amount Year (Per barrel) (In barrels) Oil swap agreements* 1998 $20.92 219 Range of Notional Fixed Prices Amount Year (Per MMBtu) (In MMBtu's) Natural gas swap agreements* 1998 $2.10-$2.67 4,370 Notional Range of Fixed Amount Year Interest Rates (In dollars) Interest rate swap agreements** 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 favorable position on all swap and collar agreements outstanding at December 31, 1997, was $1.2 million. In the event a hedge agreement does not qualify for hedge accounting or when the underlying commodity transaction or related debt instrument matures, is sold, is extinguished, or is terminated, the current favorable or unfavorable position on the open contract would be included in results of operations. The company's policy requires approval to terminate a hedge agreement prior to its original maturity. In the event a hedge agreement is terminated, the realized gain or loss at the time of termination would be deferred until the underlying commodity transaction or related debt instrument is sold or matures and would be offset by corresponding increases or decreases in the value of the underlying commodity transaction or interest on the related debt instrument. 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: 1997 1996 Carrying Fair Carrying Fair Amount Value Amount Value (In thousands) Long-term debt $306,363 $319,367 $292,420 $298,592 Preferred stocks $ 16,800 $ 12,103 $ 16,900 $ 10,762 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 short-term lines of credit from a number of banks totaling $120.4 million at December 31, 1997. 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 $3.3 million at December 31, 1997, and $4.0 million at December 31, 1996. The weighted average interest rate for borrowings outstanding at December 31, 1997 and 1996, was 8.50 percent and 7.25 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 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. 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. Since January 1, 1989, the DRIP and K-Plans have been funded by the purchase of shares of common stock on the open market except for a portion of 1997, where shares of authorized but unissued common stock were used to fund the DRIP and K-Plans. At December 31, 1997, there were 5,547,331 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 Preferred Stocks Preferred stocks at December 31 are as follows: 1997 1996 (In thousands) 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 -- 18,000 shares in 1997 (19,000 shares in 1996) $ 1,800 $ 1,900 Other preferred stock -- 4.50% Series -- 100,000 shares 10,000 10,000 4.70% Series -- 50,000 shares 5,000 5,000 15,000 15,000 Total preferred stocks 16,800 16,900 Less current maturities and sinking fund requirements 100 100 Net preferred stocks $16,700 $16,800 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 stocks: 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, 1997, is $100,000. NOTE 11 Long-term Debt and Indenture Provisions Long-term debt outstanding at December 31 is as follows: 1997 1996 (In thousands) First mortgage bonds and notes: 9 1/8% Series, due May 15, 2006 $ 20,000 $ 25,000 9 1/8% Series, paid in 1997 --- 20,000 Pollution Control Refunding Revenue Bonds, Series 1992 -- Mercer County, North Dakota, 6.65%, due June 1, 2022 15,000 15,000 Morton County, North Dakota, 6.65%, due June 1, 2022 2,600 2,600 Richland County, Montana, 6.65%, due June 1, 2022 3,250 3,250 Secured Medium-Term Notes, Series A -- 7.20%, paid in 1997 --- 5,000 6.52%, due October 1, 2004 15,000 --- 8.25%, due April 1, 2007 30,000 30,000 6.71%, due October 1, 2009 15,000 --- 8.60%, due April 1, 2012 35,000 35,000 Total first mortgage bonds and notes 135,850 135,850 Pollution control lease and note obligation, 6.20%, due March 1, 2004 3,700 4,000 Senior notes: 8.43%, due December 31, 2000 12,000 15,000 8.70%, due March 31, 2002 6,500 --- 7.35%, due July 31, 2002 5,000 5,000 7.51%, due October 9, 2003 3,000 3,000 6.86%, due October 30, 2004 12,500 --- 7.45%, due May 31, 2006 20,000 20,000 7.60%, due November 3, 2008 15,000 15,000 7.10%, due October 30, 2009 12,500 --- 7.28%, due October 30, 2012 10,000 --- Revolving lines of credit: 8.50%, expires December 31, 2002 18,000 30,000 Other revolving lines of credit at rates ranging from 6.34% to 7.25%, expiring on dates ranging from May 30, 2000, through October 6, 2001 46,000 61,800 Term credit facilities: 7.70%, due December 1, 2003 1,331 1,556 7.90%, due September 24, 2002 1,764 --- Other term credit facilities at rates ranging from 7.24% to 11.25%, due on dates ranging from February 21, 1999, through April 4, 2002 3,303 1,308 Other (85) (94) Total long-term debt 306,363 292,420 Less current maturities and sinking fund requirements 7,802 11,754 Net long-term debt $298,561 $280,666 Under the revolving lines of credit, the company and its subsidiaries have $160 million available, $64 million of which was outstanding at December 31, 1997. The amounts of scheduled long-term debt maturities and sinking fund requirements for the five years following December 31, 1997, aggregate $7.8 million in 1998; $15.2 million in 1999; $53.8 million in 2000; $14.2 million in 2001 and $33.3 million in 2002. 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 $259 million of additional first mortgage bonds at December 31, 1997. Certain of the company's other debt instruments contain restrictive covenants all of which the company is in compliance with at December 31, 1997. NOTE 12 Income Taxes Income tax expense is summarized as follows: Years ended December 31, 1997 1996 1995 (In thousands) Current: Federal $15,427 $12,617 $20,259 State 2,362 3,272 3,801 Foreign 60 60 369 17,849 15,949 24,429 Deferred: Investment tax credit -- net (1,150) (1,099) (1,028) Income taxes -- Federal 11,844 1,139 (564) State 2,200 120 220 Foreign --- (22) --- 12,894 138 (1,372) Total income tax expense $30,743 $16,087 $23,057 Components of deferred tax assets and deferred tax liabilities recognized in the company's Consolidated Balance Sheets at December 31 are as follows: 1997 1996 (In thousands) Deferred tax assets: Reserves for regulatory matters $ 32,789 $ 38,404 Natural gas available under repurchase commitment 4,821 10,521 Accrued pension costs 8,445 7,814 Deferred investment tax credits 2,714 3,160 Accrued land reclamation 3,184 3,604 Other 12,851 13,499 Total deferred tax assets 64,804 77,002 Deferred tax liabilities: Depreciation and basis differences on property, plant and equipment 123,629 121,763 Basis differences on oil and natural gas producing properties 30,726 30,361 Natural gas contract settlement and restructuring costs --- 1,926 Long-term debt refinancing costs 4,672 4,688 Other 8,168 8,461 Total deferred tax liabilities 167,195 167,199 Net deferred income tax liability $(102,391) $(90,197) The following table reconciles the change in the net deferred income tax liability from December 31, 1996, to December 31, 1997, to the deferred income tax expense included in the Consolidated Statements of Income: 1997 (In thousands) Net change in deferred income tax liability from the preceding table $12,194 Change in tax effects of income tax-related regulatory assets and liabilities 1,741 Deferred taxes associated with acquisitions 109 Deferred income tax expense for the period $14,044 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: 1997 1996 1995 Amount % Amount % Amount % (Dollars in thousands) Computed tax at federal statutory rate $29,876 35.0 $21,545 35.0 $22,642 35.0 Increases (reductions) resulting from: Depletion allowance (828) (1.0) (1,070) (1.7) (1,346) (2.1) State income taxes -- net of federal income tax benefit 3,473 4.1 2,770 4.5 2,492 3.9 Investment tax credit amortization (1,150) (1.4) (1,099) (1.8) (1,028) (1.6) Tax reserve adjustment --- --- (6,600) (10.7) --- --- Other items (628) (.7) 541 .8 297 .4 Actual taxes $30,743 36.0 $16,087 26.1 $23,057 35.6 In 1996, the company reached a settlement with the Internal Revenue Service concerning notices of deficiency issued in connection with disputed items for the 1983 through 1988 tax years and, in 1997, reached a similar settlement for the tax years 1989 through 1991. In 1996, the company reflected the effects of the 1996 settlement and the 1997 anticipated settlement and, in addition, reversed reserves which had previously been provided and were deemed to be no longer required. NOTE 13 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 of this Annual Report to Stockholders and Item 1 of the Annual Report on Form 10-K. Segment operating information at December 31, 1997, 1996 and 1995, is presented in the Consolidated Statements of Income. Depreciation, depletion and amortization by segment is summarized as follows: Years ended December 31, 1997 1996 1995 (In thousands) Electric $17,771 $ 17,053 $ 16,361 Natural gas distribution 7,013 6,880 6,719 Natural gas transmission 5,550 6,748 6,940 Construction materials and mining 10,999 6,974 6,199 Oil and natural gas production 24,434 24,996 18,606 Total depreciation, depletion and amortization $65,767 $ 62,651 $ 54,825 Segment investment information included in the accompanying Consolidated Balance Sheets at December 31 is as follows: 1997 1996 (In thousands) Identifiable assets: Electric (a) $ 326,615 $ 313,815 Natural gas distribution (a) 128,517 120,645 Natural gas transmission (a) 227,030 276,843 Construction materials and mining 235,221 171,283 Oil and natural gas production 162,785 161,647 Total identifiable assets 1,080,168 1,044,233 Corporate assets (b) 33,724 44,940 Total consolidated assets $1,113,892 $1,089,173 (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 3 percent of construction materials and mining revenues in 1997 (4 percent in 1996 and 1995) represent Knife River's direct sales of lignite coal to the company. The company's share of Knife River's 1997 sales for use at the Coyote Station, a generating station jointly owned by the company and other utilities, was approximately 3 percent and 5 percent of construction materials and mining revenues in 1997 and 1996, respectively. In 1995, 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 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 and 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. On February 14, 1997, Baldwin purchased the physical assets of Orland Asphalt located in Orland, California, including a hot-mix plant and aggregate reserves. Orland Asphalt was combined with and operates as part of Baldwin. On July 1, 1997, the company acquired two electric services companies, International Line Builders, Inc. and High Line Equipment, Inc., both located in Portland, Oregon. International Line Builders, Inc. installs and repairs transmission and distribution power lines in the western United States and Hawaii and High Line Equipment, Inc. provides related construction supplies and equipment. On July 31, 1997, Knife River purchased the 50 percent interest in Hawaiian Cement, that it did not previously own, from Adelaide Brighton Cement (Hawaii), Inc. of Adelaide, Australia. The company's initial 50 percent partnership interest in Hawaiian Cement was acquired in September 1995. See Note 15 for more discussion on this partnership investment. 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 14 Employee Benefit Plans The company has noncontributory defined benefit pension plans covering most full-time employees. Pension benefits are based primarily 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: Years ended December 31, 1997 1996 1995 (In thousands) Service cost/benefits earned during the year $ 3,889 $ 3,852 $ 3,538 Interest cost on projected benefit obligation 11,651 10,823 10,784 Return on plan assets (38,273) (24,972) (37,185) Net amortization and deferral 23,109 11,494 24,407 Special termination benefit cost --- --- 853 Total pension costs 376 1,197 2,397 Less amounts capitalized 70 131 184 Total pension expense $ 306 $ 1,066 $ 2,213 The funded status of the company's plans at December 31 is summarized as follows: 1997 1996 (In thousands) Projected benefit obligation: Vested $141,951 $122,119 Nonvested 6,204 3,923 Accumulated benefit obligation 148,155 126,042 Provision for future pay increases 30,044 24,787 Projected benefit obligation 178,199 150,829 Plan assets at market value 225,201 185,872 (47,002) (35,043) Plus: Unrecognized transition asset 6,333 7,336 Unrecognized net gains and prior service costs 48,788 35,848 Accrued pension costs $ 8,119 $ 8,141 The projected pension benefit obligation was determined using the following assumptions: 1997 1996 Discount rate 7.00% 7.50% Assumed compensation increase 4.50% 4.50% Assumed long-term rate of return on plan assets 8.00%-8.50% 8.50% The change in these assumptions had the effect of increasing the projected benefit obligation at December 31, 1997, by $12 million. 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 generally 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: Years ended December 31, 1997 1996 1995 (In thousands) Service cost/benefits earned during the year $ 1,272 $ 1,333 $ 1,226 Interest cost on accumulated postretirement benefit obligation 4,691 4,701 4,777 Return on plan assets (5,380) (2,491) (183) Amortization of transition obligation 2,458 2,458 2,458 Net amortization and deferral 3,527 1,260 (719) Total postretirement benefits cost 6,568 7,261 7,559 Less amounts capitalized 625 735 442 Total postretirement benefits expense $ 5,943 $ 6,526 $ 7,117 The funded status of the company's plans at December 31 is summarized as follows: 1997 1996 (In thousands) Accumulated postretirement benefit obligation: Retirees eligible for benefits $ 44,876 $40,775 Active employees fully eligible for benefits 1,646 --- Active employees not fully eligible 27,316 24,833 Total 73,838 65,608 Plan assets at market value 30,595 21,712 43,243 43,896 Less: Unrecognized transition obligation 36,864 39,322 Unrecognized net loss (gain) (2,679) 3,693 Accrued postretirement benefits cost $ 9,058 $ 881 The accumulated postretirement benefit obligation was determined using the following assumptions: 1997 1996 Discount rate 7.00% 7.50% Compensation increase as it applies to life insurance benefits 4.50% 4.50% Long-term rate of return on plan assets 7.50% 7.50% Health care cost trend rate 7.00%-9.00% 9.00% Health care cost trend rate -- ultimate 5.00%-6.00% 6.00% Year in which ultimate trend rate achieved 1999-2004 1999 The change in these assumptions had the effect of increasing the accumulated postretirement benefit obligation at December 31, 1997, by $5 million. 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, 1997, by $3.8 million and the aggregate of the service and interest cost components of postretirement benefits expense by $239,000. 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's policy with respect to most plans is to fund the annual expense amount. One subsidiary of KRC Holdings has a policy to fund postretirement benefits on a cash basis. 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 both 1997 and 1996 and $1.9 million in 1995. 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. Under the KESOP the option price equals the market value of the stock 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 a change in control of the company. The options expire 10 years after the date of grant. The company also adopted a Non-Employee Director Option Plan (Director Plan) and an Executive Long-Term Incentive Plan (Executive Plan) in 1997. Under the KESOP, Director Plan and Executive Plan, the company is authorized to grant options for up to 2.6 million shares of common stock and has granted options on 490,473 shares through December 31, 1997. Had the company recorded compensation expense for the fair value of options granted consistent with SFAS No. 123, "Accounting for Stock- Based Compensation" (SFAS No. 123), net income would have been reduced on a pro forma basis by $51,400 in 1997 and $48,000 in both 1996 and 1995. On a pro forma basis, there would have been no effect on reported basic earnings per share for 1997, 1996 and 1995. There would have been no effect on reported diluted earnings per share in 1997 and 1995, however diluted earnings per share would have been reduced on a pro forma basis by $.01 in 1996. Since SFAS No. 123 does not require this accounting to be applied to options granted prior to January 1, 1995, the resulting pro forma compensation costs may not be representative of that to be expected in future years. A summary of the status of the KESOP and Director Plan at December 31, 1997, 1996 and 1995, and changes during the years then ended are as follows: 1997 1996 1995 Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price Balance at beginning of year 423,977 $17.66 468,737 $17.48 192,284 $15.82 Granted 15,000 24.56 --- --- 294,956 18.50 Forfeited (9,067) 17.11 --- --- (2,700) 20.83 Exercised (33,790) 15.75 (44,760) 15.75 (15,803) 15.75 Balance at end of year 396,120 18.10 423,977 17.66 468,737 17.48 Exercisable at end of year 74,974 $17.51 93,764 $15.75 138,524 $15.75 Exercise prices on options outstanding at December 31, 1997, range from $15.75 to $24.56 with a weighted average remaining contractual life of approximately 7 years. The weighted average fair value of each option granted in 1997 and 1995 is $3.13 and $2.67, respectively. 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 1997 and 1995 were a risk-free interest rate of 6.60 percent and 7.80 percent, respectively, an expected dividend yield of 5.48 percent and 5.80 percent, respectively, an expected life of 7 years and 10 years, respectively, and expected volatility of 14.51 percent and 15.80 percent, respectively. The company has Tax Deferred Compensation Savings Plans for eligible employees. Generally 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 $2.1 million in 1997 and $1.9 million in both 1996 and 1995. NOTE 15 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. Knife River Dakota, Inc., a wholly owned subsidiary of KRC Holdings, Inc. acquired the remaining 50 percent interest in Hawaiian Cement from the previous owner, Adelaide Brighton Cement (Hawaii), Inc. of Adelaide, Australia, on July 31, 1997. Hawaiian Cement is a partnership headquartered in Honolulu, Hawaii, and 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. In August 1997, the company began consolidating Hawaiian Cement into its financial statements. Prior to August 1997, the company's net investment in Hawaiian Cement was not consolidated and was accounted for by the equity method. The company's original 50 percent investment is included in "Investments" in the accompanying Consolidated Balance Sheets at December 31, 1996, while its share of operating results for the seven months ended July 31, 1997, the year ended December 31, 1996, and the four months ended December 31, 1995, is included in "Other income -- net" in the accompanying Consolidated Statements of Income for the years ended December 31, 1997, 1996 and 1995, respectively. Summarized financial information for Hawaiian Cement, when accounted for by the equity method, includes: current assets; net property, plant and equipment; current liabilities; and, other liabilities, as of December 31, 1996, (in millions) of $17.3, $52.3, $10.1 and $15.0, respectively. Operating results for the seven months ended July 31, 1997, for the year ended December 31, 1996, and for the four months ended December 31, 1995, (in millions) were net sales of $33.5, $70.1 and $24.4; operating margin of $4.7, $9.9 and $5.1; and income before income taxes of $2.0, $5.4 and $2.8, respectively. NOTE 16 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 financing 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: 1997 1996 (In thousands) Big Stone Station: Utility plant in service $ 49,467 $ 48,907 Accumulated depreciation 27,971 26,676 $ 21,496 $ 22,231 Coyote Station: Utility plant in service $121,604 $122,320 Accumulated depreciation 53,107 52,721 $ 68,497 $ 69,599 NOTE 17 Quarterly Data (Unaudited) The following unaudited information shows selected items by quarter for the years 1997 and 1996: First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per share amounts) 1997 Operating revenues $139,811 $125,380 $163,699 $178,784 Operating expenses 109,055 106,932 134,675 145,451 Operating income 30,756 18,448 29,024 33,333 Net income 14,597 8,741 14,195 17,084 Earnings per common share: Basic .50 .30 .48 .58 Diluted .50 .30 .48 .58 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: Basic .45 .30 .29 .53 Diluted .45 .30 .29 .53 Certain company 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 18 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. 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. The following information includes the company's proportionate share of all its oil and natural gas interests held by both Fidelity Oil and Williston Basin. The following table sets forth capitalized costs and accumulated depreciation, depletion and amortization related to oil and natural gas producing activities at December 31: 1997 1996 1995 (In thousands) Subject to amortization $252,291 $223,409 $173,501 Not subject to amortization 9,408 6,792 8,831 Total capitalized costs 261,699 230,201 182,332 Accumulated depreciation, depletion and amortization 95,611 71,554 49,498 Net capitalized costs $166,088 $158,647 $132,834 Net capital expenditures, including those not subject to amortization, related to oil and natural gas producing activities are as follows: Years ended December 31, 1997 1996 1995 (In thousands) Acquisitions $ 59 $23,284 $ 9,159 Exploration 13,344 8,101 7,678 Development 18,874 19,979 24,955 Net capital expenditures $32,277 $51,364 $41,792 The following summary reflects income resulting from the company's operations of oil and natural gas producing activities, excluding corporate overhead and financing costs: Years ended December 31, 1997 1996 1995 (In thousands) Revenues* $77,756 $75,335 $53,484 Production costs 23,251 21,296 16,888 Depreciation, depletion and amortization 24,864 25,629 19,058 Pretax income 29,641 28,410 17,538 Income tax expense 10,968 10,875 6,397 Results of operations for producing activities $18,673 $17,535 $11,141 * Includes $9.4 million, $7.0 million and $4.7 million of revenues for 1997, 1996 and 1995, respectively, related to Williston Basin's natural gas production activities which are included in "Natural gas" operating revenues in the Consolidated Statements of Income. The following table summarizes the company's estimated quantities of proved oil and natural gas reserves at December 31, 1997, 1996 and 1995, 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. 1997 1996 1995 Natural Natural Natural Oil Gas Oil Gas Oil Gas (In thousands of barrels/Mcf) Proved developed and undeveloped reserves: Balance at beginning of year 16,100 200,200 14,200 179,000 12,500 154,200 Production (2,100) (20,400) (2,100) (20,400) (2,000) (17,500) Extensions and discoveries 600 12,100 600 27,000 1,800 23,800 Purchases of proved reserves --- 200 2,900 9,900 1,100 6,700 Sales of reserves in place (200) (2,300) (700) (3,700) (300) (200) Revisions to previous estimates due to improved secondary recovery techniques and/or changed economic conditions 500 (4,900) 1,200 8,400 1,100 12,000 Balance at end of year 14,900 184,900 16,100 200,200 14,200 179,000 Proved developed reserves: January 1, 1995 12,200 147,200 December 31, 1995 13,600 156,400 December 31, 1996 15,400 168,200 December 31, 1997 14,500 163,800 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, 1997, applicable to the company's $852,000 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: 1997 1996 1995 (In thousands) Future net cash flows before income taxes $306,600 $580,300 $267,300 Future income tax expenses 86,600 194,200 76,100 Future net cash flows 220,000 386,100 191,200 10% annual discount for estimated timing of cash flows 81,000 152,100 70,300 Discounted future net cash flows relating to proved oil and natural gas reserves $139,000 $234,000 $120,900 The following are the sources of change in the standardized measure of discounted future net cash flows by year: 1997 1996 1995 (In thousands) Beginning of year $234,000 $120,900 $ 94,900 Net revenues from production (54,500) (54,000) (36,400) Change in net realization (158,400) 125,800 26,300 Extensions, discoveries and improved recovery, net of future production-related costs 19,400 43,500 31,200 Purchases of proved reserves 200 49,600 10,900 Sales of reserves in place (2,800) (6,700) (1,000) Changes in estimated future development costs -- net of those incurred during the year 7,700 (2,400) (8,900) Accretion of discount 32,800 16,900 12,300 Net change in income taxes 62,100 (69,200) (17,100) Revisions of previous quantity estimates (1,300) 8,700 8,900 Other (200) 900 (200) Net change (95,000) 113,100 26,000 End of year $139,000 $234,000 $120,900 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 of MDU Resources Group, Inc. (a Delaware corporation) and Subsidiaries as of December 31, 1997 and 1996, and the related consolidated statements of income, common stockholders' equity and cash flows for each of the three years in the period ended December 31, 1997. 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, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Minneapolis, Minnesota January 22, 1998 1997 1996 1995 Selected Financial Data Operating revenues: (000's) Electric $ 164,351 $ 138,761 $ 134,609 Natural gas 200,789 175,408 167,787 Construction materials and mining 174,147 132,222 113,066 Oil and natural gas production 68,387 68,310 48,784 $ 607,674 $ 514,701 $ 464,246 Operating income: (000's) Electric $ 33,089 $ 29,476 $ 29,898 Natural gas distribution 10,410 11,504 6,917 Natural gas transmission 29,169 30,231 25,427 Construction materials and mining 14,602 16,062 14,463 Oil and natural gas production 24,291 24,252 13,871 $ 111,561 $ 111,525 $ 90,576 Earnings on common stock: (000's) Electric $ 13,388 $ 11,436 $ 12,000 Natural gas distribution 4,514 4,892 1,604 Natural gas transmission 11,317 2,459 8,416 Construction materials and mining 10,111 11,521 10,819 Oil and natural gas production 14,505 14,375 8,002 Earnings on common stock before cumulative effect of accounting change 53,835 44,683 40,841 Cumulative effect of accounting change --- --- --- $ 53,835 $ 44,683 $ 40,841 Earnings per common share before cumulative effect of accounting change -- diluted $ 1.86 $ 1.57 $ 1.43 Cumulative effect of accounting change --- --- --- $ 1.86 $ 1.57 $ 1.43 Pro forma amounts assuming retroactive application of accounting change: Net income (000's) $ 54,617 $ 45,470 $ 41,633 Earnings per common share -- diluted $ 1.86 $ 1.57 $ 1.43 Common Stock Statistics Weighted average common shares outstanding -- diluted (000's) 28,985 28,549 28,526 Dividends per common share $ 1.13 $ 1.10 $ 1.0782 Book value per common share $ 13.26 $ 12.31 $ 11.85 Market price per common share (year end) $ 31.63 $ 23.00 $ 19.88 Market price ratios: Dividend payout 61% 70% 76% Yield 3.6% 4.8% 5.5% Price/earnings ratio 17.0x 14.6x 13.9x Market value as a percent of book value 238.5% 186.8% 167.7% Profitability Indicators Return on average common equity 14.6% 13.0% 12.3% Return on average invested capital 10.3% 9.5% 9.2% Interest coverage 6.0x 5.4x 3.9x Fixed charges coverage, including preferred dividends 3.4x 2.7x 3.0x General Total assets (000's) $1,113,892 $1,089,173 $1,056,479 Net long-term debt (000's) $ 298,561 $ 280,666 $ 237,352 Redeemable preferred stock (000's) $ 1,800 $ 1,900 $ 2,000 Capitalization ratios: Common stockholders' equity 55% 54% 57% Preferred stocks 2 3 3 Long-term debt 43 43 40 100% 100% 100% 1994 1993 1992 Selected Financial Data Operating revenues: (000's) Electric $ 133,953 $ 131,109 $ 123,908 Natural gas 160,970 178,981 159,438 Construction materials and mining 116,646 90,397 45,032 Oil and natural gas production 37,959 39,125 33,797 $ 449,528 $ 439,612 $ 362,175 Operating income: (000's) Electric $ 27,596 $ 30,520 $ 30,188 Natural gas distribution 3,948 4,730 4,509 Natural gas transmission 21,281 20,108 21,331 Construction materials and mining 16,593 16,984 11,532 Oil and natural gas production 8,757 11,750 9,499 $ 78,175 $ 84,092 $ 77,059 Earnings on common stock: (000's) Electric $ 11,719 $ 12,652* $ 13,302 Natural gas distribution 285 1,182* 1,370 Natural gas transmission 6,155 4,713 3,479 Construction materials and mining 11,622 12,359 10,662 Oil and natural gas production 9,267 7,109 5,751 Earnings on common stock before cumulative effect of accounting change 39,048 38,015* 34,564 Cumulative effect of accounting change --- 5,521 --- $ 39,048 $ 43,536 $ 34,564 Earnings per common share before cumulative effect of accounting change -- diluted $ 1.37 $ 1.34* $ 1.21 Cumulative effect of accounting change --- .19 --- $ 1.37 $ 1.53 $ 1.21 Pro forma amounts assuming retroactive application of accounting change: Net income (000's) $ 39,845 $ 38,817 $ 35,852 Earnings per common share -- diluted $ 1.37 $ 1.34 $ 1.23 Common Stock Statistics Weighted average common shares outstanding -- diluted (000's) 28,509 28,534 28,494 Dividends per common share $ 1.0533 $ 1.0133 $ .9733 Book value per common share $ 11.49 $ 11.17 $ 10.66 Market price per common share (year end) $ 18.08 $ 21.00 $ 17.58 Market price ratios: Dividend payout 77% 76%* 80% Yield 5.9% 5.0% 5.6% Price/earnings ratio 13.2x 15.8x* 14.5x Market value as a percent of book value 157.4% 188.0% 165.0% Profitability Indicators Return on average common equity 12.1% 12.3%* 11.6% Return on average invested capital 9.1% 9.4%* 8.7% Interest coverage 3.3x 3.4x* 3.3x Fixed charges coverage, including preferred dividends 2.8x 2.9x* 2.4x General Total assets (000's) $1,004,718 $1,041,051 $1,024,510 Net long-term debt (000's) $ 217,693 $ 231,770 $ 249,845 Redeemable preferred stock (000's) $ 2,100 $ 2,200 $ 2,300 Capitalization ratios: Common stockholders' equity 58% 56% 53% Preferred stocks 3 3 3 Long-term debt 39 41 44 100% 100% 100% * Before cumulative effect of an accounting change reflecting the accrual of estimated unbilled revenues. 1997 1996 1995 Electric Operations Sales to ultimate consumers (thousand kWh) 2,041,191 2,067,926 1,993,693 Sales for resale (thousand kWh) 361,954 374,535 408,011 Electric system generating and firm purchase capability -- kW (Interconnected system) 487,500 481,800 472,400 Demand peak -- kW (Interconnected system) 404,600 393,300 412,700 Electricity produced (thousand kWh) 1,826,770 1,829,669 1,718,077 Electricity purchased (thousand kWh) 769,679 809,261 867,524 Cost of fuel and purchased power per kWh $.018 $.017 $.016 Natural Gas Distribution Operations Sales (Mdk) 34,320 38,283 33,939 Transportation (Mdk) 10,067 9,423 11,091 Weighted average degree days -- % of previous year's actual 85% 114% 105% Natural Gas Transmission Operations Natural gas transmission: Sales for resale (Mdk) --- --- --- Transportation (Mdk) 85,464 82,169 68,015 Produced (Mdk) 6,949 6,073 4,981 Net recoverable reserves (MMcf) 127,300 133,400 113,000 Energy marketing: Natural gas volumes (Mdk) 14,971 4,670 3,556 Propane (thousand gallons) 10,005 9,689 7,471 Construction Materials and Mining Operations Construction materials: (000's) Aggregates (tons sold) 5,113 3,374 2,904 Asphalt (tons sold) 758 694 373 Ready-mixed concrete (cubic yards sold) 516 340 307 Recoverable aggregate reserves (tons) 169,375 119,800 68,000 Coal: (000's) Sales (tons) 2,375 2,899 4,218 Recoverable reserves (tons) 226,560 228,900 231,900 Oil and Natural Gas Production Operations Production: Oil (000's of barrels) 2,088 2,149 1,973 Natural gas (MMcf) 13,192 14,067 12,319 Average sales prices: Oil (per barrel) $ 17.50 $ 17.91 $ 15.07 Natural gas (per Mcf) $ 2.41 $ 2.09 $ 1.51 Net recoverable reserves: Oil (000's of barrels) 14,900 16,100 14,200 Natural gas (MMcf) 57,600 66,800 66,000 1994 1993 1992 Electric Operations Sales to ultimate consumers (thousand kWh) 1,955,136 1,893,713 1,829,933 Sales for resale (thousand kWh) 444,492 510,987 352,550 Electric system generating and firm purchase capability -- kW (Interconnected system) 470,900 465,200 460,200 Demand peak -- kW (Interconnected system) 369,800 350,300 339,100 Electricity produced (thousand kWh) 1,901,119 1,870,740 1,774,322 Electricity purchased (thousand kWh) 700,912 701,736 593,612 Cost of fuel and purchased power per kWh $.017 $.016 $.016 Natural Gas Distribution Operations Sales (Mdk) 31,840 31,147 26,681 Transportation (Mdk) 9,278 12,704 13,742 Weighted average degree days -- % of previous year's actual 92% 115% 98% Natural Gas Transmission Operations Natural gas transmission: Sales for resale (Mdk) --- 13,201 16,841 Transportation (Mdk) 63,870 59,416 64,498 Produced (Mdk) 4,732 3,876 3,551 Net recoverable reserves (MMcf) 99,300 --- --- Energy marketing: Natural gas volumes (Mdk) 7,301 6,827 3,292 Propane (thousand gallons) 6,462 2,210 --- Construction Materials and Mining Operations Construction materials: (000's) Aggregates (tons sold) 2,688 2,391 263 Asphalt (tons sold) 391 141 --- Ready-mixed concrete (cubic yards sold) 315 157 --- Recoverable aggregate reserves (tons) 71,000 74,200 20,600 Coal: (000's) Sales (tons) 5,206 5,066 4,913 Recoverable reserves (tons) 236,100 230,600 235,700 Oil and Natural Gas Production Operations Production: Oil (000's of barrels) 1,565 1,497 1,531 Natural gas (MMcf) 9,228 8,817 5,024 Average sales prices: Oil (per barrel) $ 13.14 $ 14.84 $ 16.74 Natural gas (per Mcf) $ 1.84 $ 1.86 $ 1.53 Net recoverable reserves: Oil (000's of barrels) 12,500 11,200 12,200 Natural gas (MMcf) 54,900 50,300 37,200 EX-21 5 SUBSIDIARIES SUBSIDIARIES OF MDU RESOURCES GROUP, INC. March 6, 1998 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 Fidelity Oil Co. Delaware Fidelity Oil Holdings, Inc. Delaware High Line Equipment, Inc. Delaware ILB Hawaii, Inc. Hawaii International Line Builders, Inc. Delaware Knife River Corporation Delaware Knife River Dakota, Inc. Delaware Knife River Hawaii, Inc. Delaware Knife River Marine, Inc. Delaware KRC Aggregate, Inc. Delaware KRC Holdings, Inc. Delaware LTM, Incorporated Oregon Medford Ready Mix, Inc. Delaware Morse Bros., Inc. Oregon Prairie Propane, Inc. Delaware Prairielands Energy Marketing, Inc. Delaware Rogue Aggregates, Inc. Oregon S2 - F Corp. Oregon Utility Services, Inc. Delaware WBI Canadian Pipeline, Ltd. Canada Williston Basin Interstate Pipeline Company Delaware EX-23.A,B,C 6 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 22, 1998 included in the MDU Resources Group, Inc. Annual Report to Stockholders for 1997. 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 and No. 333-06127, and on Form S-8, No. 33-54486, No. 33-53896, No. 333-06103, No. 333-06105, No. 333-27879 and No. 333-27877. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Minneapolis, Minnesota March 6, 1998 CONSENT OF ENGINEER We hereby consent to the reference to our reports dated January 12, 1998, 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 and No. 333-06127 and on Form S-8, No. 33-54486, No. 33-53896, No. 333-06103, No. 333-06105, No. 333-27879 and No. 333-27877 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 March 6, 1998 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 and No. 333-06127, and on Form S-8, No. 33-54486, No. 33-53896, No. 333-06103, No. 333-06105, No. 333-27879 and No. 333-27877 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 March 6, 1998 EX-27 7 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 FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATMENTS. 0000067716 MDU RESOURCES GROUP, INC. 1000 US 12-MOS DEC-31-1997 JAN-01-1997 DEC-31-1997 1 PER-BOOK 530,844 327,627 179,916 75,505 0 1,113,892 97,047 76,526 212,723 386,296 1,700 15,000 298,561 3,347 0 0 7,802 100 0 0 401,086 1,113,892 607,674 30,743 496,113 526,856 80,818 4,008 84,826 30,209 54,617 782 53,835 32,653 12,462 138,629 1.86 1.86
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