-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, j0sF8UsBytnoOC9K6D9qr+keTPtIGLeG+w82akPjWFpUWLO9DsjlLOZQR5vx4jHM P0ck2cIwfXeLmhSJoaDMcg== 0000067716-94-000006.txt : 19940307 0000067716-94-000006.hdr.sgml : 19940307 ACCESSION NUMBER: 0000067716-94-000006 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940303 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MDU RESOURCES GROUP INC CENTRAL INDEX KEY: 0000067716 STANDARD INDUSTRIAL CLASSIFICATION: 4932 IRS NUMBER: 410423660 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-03480 FILM NUMBER: 94514389 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 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, 1993 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______________ to ____________ Commission file number 1-3480 MDU Resources Group, Inc. (Exact name of registrant as specified in its charter) Delaware 41-0423660 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 400 North Fourth Street 58501 Bismarck, North Dakota (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code: (701) 222-7900 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange Common Stock, par value $5 on which registered and Preference Share Purchase Rights New York 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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X . No. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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 25, 1994: $569,540,000. Indicate the number of shares outstanding of each of the Registrant's classes of common stock, as of February 25, 1994: 18,984,654 shares. DOCUMENTS INCORPORATED BY REFERENCE. 1. Pages 27 through 53 of the Annual Report to Stockholders for 1993, incorporated in Part II, Items 6 and 8 of this Report. 2. Proxy Statement, dated March 7, 1994, incorporated in Part III, Items 10, 11, 12 and 13 of this Report. CONTENTS PART I Items 1 and 2 -- Business and Properties General Montana-Dakota Utilities Co. Electric Generation, Transmission and Distribution Retail Natural Gas and Propane Distribution Williston Basin Interstate Pipeline Company Knife River Coal Mining Company Coal Operations Construction Materials Operations Consolidated Mining and Construction Materials Operations Fidelity Oil Group Item 3 -- Legal Proceedings Item 4 -- Submission of Matters to a Vote of Security Holders PART II Item 5 -- Market for the Registrant's Common Stock and Related Stockholder Matters Item 6 -- Selected Financial Data Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations Item 8 -- Financial Statements and Supplementary Data Item 9 -- Change in and Disagreements with Accountants on Accounting and Financial Disclosure PART III Item 10 -- Directors and Executive Officers of the Registrant Item 11 -- Executive Compensation Item 12 -- Security Ownership of Certain Beneficial Owners and Management Item 13 -- Certain Relationships and Related Transactions PART IV Item 14 -- Exhibits, Financial Statement Schedules and Reports on Form 8-K PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES General MDU Resources Group, Inc. (Company) is a diversified natural resource company which was incorporated under the laws of the State of Delaware in 1924. Its principal executive offices are at 400 North Fourth Street, Bismarck, North Dakota 58501, telephone (701) 222-7900. Montana-Dakota Utilities Co. (Montana-Dakota), the public utility division of the Company, provides electric and/or natural gas and propane distribution service at retail to 251 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 Coal Mining Company (Knife River), the Fidelity Oil Group (Fidelity Oil) and Prairielands Energy Marketing, Inc. (Prairielands). 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. Knife River surface mines and markets low sulfur lignite coal at mines located in Montana and North Dakota and, through its wholly-owned subsidiary, KRC Holdings, Inc., surface mines and markets aggregates and related construction materials in the Anchorage, Alaska area, southern Oregon and north-central California. Fidelity Oil is comprised of Fidelity Oil Co. and Fidelity Oil Holdings, Inc., which own oil and natural gas interests in the western United States, the Gulf Coast and Canada through investments with several oil and natural gas producers. Prairielands 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 and, through its wholly-owned subsidiary, Gwinner Propane, Inc., operating bulk propane facilities in southeastern North Dakota. 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. Details applicable to the Company's continuing construction program and the expansion of the Company's non-regulated mining and construction materials, and oil and natural gas production operations are discussed in the sections devoted to each business. See Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of "Liquidity and Capital Commitments" and the anticipated level of funds to be generated internally for these activities. All of the Company's electric and natural gas distribution properties, with certain exceptions, are subject to the lien of the Indenture of Mortgage dated May 1, 1939, as supplemented and amended, from the Company to The Bank of New York and W. T. Cunningham, successor trustees. As of December 31, 1993, the Company had 2,052 full-time employees with 96 employed at MDU Resources Group, Inc., including Fidelity Oil and Prairielands, 1,224 at Montana-Dakota, 271 at Williston Basin and 461 at Knife River. Approximately 577 and 86 of the Montana-Dakota and Williston Basin employees, respectively, are represented by the International Brotherhood of Electrical Workers. Labor contracts with such employees are in effect through August 1995, for Montana-Dakota and December 1994, for Williston Basin. Knife River's coal operations have a labor contract through August 1995, with the United Mine Workers of America, which represents its hourly workforce approximating 136 employees. Knife River's construction materials operations have eight labor contracts covering 122 employees. These contracts have expiration dates ranging from February 1994, to May 1997. The financial results and data applicable to each of the Company's business segments as well as their financing requirements are set forth in Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations". Any reference to the Company's Consolidated Financial Statements and Notes thereto shall be to the Consolidated Financial Statements and Notes thereto contained on pages 27 through 51 in the Company's Annual Report to Stockholders for 1993 (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 110,000 residential, commercial, industrial and municipal customers located in 176 communities and adjacent rural areas as of December 31, 1993. 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 Demand", and over 3,100 miles and 3,800 miles of transmission lines 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, 1993, Montana-Dakota's net electric plant investment approximated $276.1 million. 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. These operations, including retail rates, service, accounting and, in certain cases, security issuances are also subject to regulation by the public service commissions of North Dakota, Montana, South Dakota and Wyoming. The percentage of Montana-Dakota's 1993 electric utility retail operating revenues by jurisdiction is as follows: North Dakota -- 60%; Montana -- 23%; South Dakota -- 8% and Wyoming -- 9%. System Supply and Demand -- Through an interconnected electric system, Montana-Dakota serves markets in portions of the following states and their 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 (including interests in the Big Stone Station and the Coyote Station aggregating 22.7% and 25.0%, respectively) 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 414,150 kW. The four principal generating stations are steam-turbine generating units using lignite coal for fuel. The nameplate rating for Montana-Dakota's ownership interest in these four plants 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 ultimately up to 66,000 kW of participation power from Basin Electric Power Cooperative (Basin) (51,000 kW in 1993) for its interconnected system as described herein. The following table sets forth details applicable to the Company's electric generating stations: Nameplate Summer 1993 Net Generating Rating Capability Generation Station Type (kW) (kW) (MWh) North Dakota -- Coyote* Steam 103,647 106,500 666,355 Heskett Steam 86,000 102,000 434,292 Williston Combustion Turbine 7,800 10,000 (29)** South Dakota -- Big Stone* Steam 94,111 101,750 525,547 Montana -- Lewis & Clark Steam 44,000 43,800 233,104 Glendive Combustion Turbine 34,780 30,100 7,051 Miles City Combustion Turbine 23,150 20,000 4,420 393,488 414,150 1,870,740 *Reflects Montana-Dakota's ownership interest. **Station use exceeded generation. Virtually all of the current fuel requirements of Montana- Dakota's principal generating stations are met with lignite coal supplied by Knife River under various long-term contracts. During the years ended December 31, 1989, through December 31, 1993, the average cost of lignite 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 lignite coal so consumed was as follows: Years Ended December 31, 1993 1992 1991 1990 1989 Average cost of lignite coal per million Btu. . . . $.96 $.97 $.99 $.98 $1.00 Average cost of lignite coal per ton. . . . . . $12.78 $12.79 $13.06 $13.10 $13.22 In recent years, Knife River, in response to competitive pressure, has reduced its coal prices at its mine locations, all of which provide coal to Montana-Dakota. Most recently, Montana- Dakota and Knife River entered into a new five-year coal sales contract stipulating reduced coal prices for sales made from Knife River's Savage Mine to the Lewis & Clark Station effective January 1, 1993. This contract replaced an existing contract which was to expire in September 1993. This reduction has allowed Montana-Dakota to be more competitive in the Mid-Continent Area Power Pool (MAPP). The maximum electric peak demand experienced to date attributable to sales to retail customers on the interconnected system was 387,100 kW in July 1991. Due to an unseasonably cool summer, the 1993 summer peak was only 350,300 kW. The summer peak, assuming normal weather, was previously forecasted to have been approximately 384,500 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 1998 will approximate 1.8% annually. Kilowatt-hour (kWh) sales would have increased approximately 1% annually during the most recent five years and, on a normalized basis, Montana-Dakota's latest forecast indicates that its sales growth rates through 1998 will approximate 1.7% annually. This moderate improvement in sales is due, in part, to stabilized economic conditions and a recovery from drought conditions which had prevailed for several years. Montana-Dakota has a participation power contract through October 31, 2006, with Basin for the ultimate purchase of up to approximately 66,000 kW (14.8% of the unit's maximum net capacity) from the Antelope Valley Station II, a lignite coal-fired generating station located near Beulah, North Dakota. Currently Montana-Dakota purchases 51,000 kW of such capacity and, under the terms of the contract, Montana-Dakota will purchase, on an incremental basis, an additional 5,000 kW of capacity each year for the years 1994 through 1996 for a total of 66,000 kW annually for the period 1996 through October 31, 2006. Montana-Dakota anticipates having a summer capacity position (after providing for the 15% MAPP reserve requirement) as follows: 1994 -- 13,000 kW reserve; 1995 -- 14,000 kW reserve; 1996 -- 13,000 kW reserve; 1997 -- 6,000 kW reserve and 1998 --(3,000) kW deficiency. Montana-Dakota has major interconnections with its neighboring utilities, all of whom are MAPP members, which it considers 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. That system is supplied through an interconnection with Pacific Power & Light Company under a long-term supply contract through the year 1996. 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 the implementation of a peak shaving load management system, Montana- Dakota estimates this annual peak will not be exceeded through 1995. Montana-Dakota has in place an integrated resource plan which is used in planning for a reliable future supply of electricity which will coincide with anticipated customer demand. On the supply side, Montana-Dakota currently estimates that it has adequate capacity available through existing generating stations and long-term firm purchase contracts until the late 1990s. At that time, it is anticipated that Montana-Dakota will need to construct a natural gas combustion turbine peaking station in order to meet its interconnected system's peak demand requirements. Emerging generation technologies and purchases from other sources, if available, are alternatives which will be continually monitored as supply options. On the demand side, Montana-Dakota currently offers rate and other incentives to its customers designed to promote conservation, load shifting and peak shaving efforts. The development and evaluation of other economically feasible strategic marketing programs continues. Montana-Dakota has filed, as required pursuant to established filing requirements, its integrated resource plan with the Montana and North Dakota public service commissions. Regulatory Matters -- The cost of coal purchased from Knife River for use at Montana-Dakota's electric generating stations is subject to certain recoverability limits established by the Montana, North Dakota and South Dakota public service commissions. These limits allow for the recovery of coal costs which are established based on the commissions' determination of a reasonable return on equity for Knife River's coal operations, regardless of the actual cost of coal purchased. Although disallowances have occurred in the past, such amounts have not been material to Montana-Dakota's electric operations. Fuel adjustment clauses contained in North Dakota and South Dakota jurisdictional electric rate schedules and expedited rate filing procedures in Wyoming allow Montana-Dakota to reflect increases or decreases in fuel and purchased power costs (excluding capacity costs) on a timely basis. As a result of a settlement approved by the Wyoming Public Service Commission in late November 1993, Montana-Dakota will be developing and implementing a tariff for its Wyoming electric operations which will permit the reflection of increases or decreases in capacity and load management costs in its electric rates. Development and implementation is anticipated to be completed by April 1, 1994. In Montana (23% of electric revenues), such cost changes are includible in general rate filings. On April 30, 1993, Montana-Dakota filed a general electric rate case with the Wyoming Public Service Commission (WPSC), requesting an increase of $379,000, or 3.6 percent. On November 30, 1993, Montana-Dakota and the WPSC reached a settlement of this proceeding providing for an increase of $52,000, effective December 1, 1993, and authorizing the capacity and load management tracking mechanisms previously discussed. As a result of a 1993 inquiry by the North Dakota Public Service Commission (NDPSC) regarding the level of Montana-Dakota's electric earnings, the NDPSC reconsidered its prior order in which it had permitted deferral, for a limited time period, of additional expenses related to the implementation by Montana-Dakota of Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS No. 106). On January 19, 1994, the NDPSC issued an order which requires the expensing, commencing January 1, 1994, of the ongoing SFAS No. 106 incremental expense estimated at approximately $1.0 million annually. The order further stated that the SFAS No. 106 costs deferred by Montana-Dakota in 1993 are expected to be recoverable in future rates. Capital Requirements -- The following schedule (in millions of dollars) summarizes the 1993 actual and 1994 through 1996 anticipated construction expenditures applicable to Montana-Dakota's electric operations: Estimated Actual 1993 1994 1995 1996 Production . . . . . . . . . $ 5.1 $ 4.2 $ 4.0 $ 6.0 Transmission . . . . . . . . 2.0 1.9 4.8 3.4 Distribution, General and Common . . . . . . . . 9.1 10.8 11.0 10.0 $16.2 $16.9 $19.8 $19.4 Environmental Matters -- Montana-Dakota's electric operations, are subject to extensive federal, state and local laws and regulations providing for environmental, 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 applicable regulations, including environmental regulations, as well as all applicable permitting requirements. Governmental regulations establishing environmental protection standards are continually evolving. Therefore, the character, scope, cost and availability of the measures which will permit compliance with evolving laws or regulations, cannot now be accurately predicted. The Clean Air Act (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 lignite coal fired. All of these stations, with the exception of the Big Stone Station, are 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. Current assessments indicate that the emissions requirement could be met at the Big Stone Station through various alternatives including installation of a sulfur scrubber, switching to lower sulfur ("compliance") coal, utilization of processed or "clean" coal, or fuel blending. Montana-Dakota is unable to predict which alternative may be used or the costs that may be associated with each of the alternatives, some of which may be substantial. In addition, the Act will limit the amount of nitrous oxide emissions, although the final rules as they relate to the majority of Montana-Dakota's generating stations have not yet been finalized. Accordingly, Montana-Dakota is unable to determine what modifications may be necessary or the costs associated with any changes which may be required. Montana-Dakota incurred costs of approximately $1.9 million in 1993 for the installation of sulfur dioxide monitoring systems at the Heskett and Lewis & Clark stations. Montana-Dakota does not expect to incur any additional substantial expenditures related to environmental facilities during 1994 through 1996, subject to evolving regulations. Retail Natural Gas and Propane Distribution General -- Montana-Dakota sells natural gas at retail, serving over 186,000 residential, commercial and industrial customers located in 133 communities and adjacent rural areas as of December 31, 1993, and provides natural gas transportation services to certain customers on its system. These services are provided through a natural gas distribution system aggregating over 3,800 miles. In addition, Montana-Dakota sells propane at retail, serving over 600 residential and commercial customers in two small communities through propane distribution systems aggregating 13 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, 1993, Montana-Dakota's net gas and propane distribution plant investment approximated $72.1 million. The natural gas distribution operations of Montana-Dakota are subject to regulation by the public service commissions of North Dakota, Montana, South Dakota and Wyoming regarding retail rates, service, accounting and, in certain instances, security issuances. The percentage of Montana-Dakota's 1993 natural gas and propane utility operating revenues by jurisdiction is as follows: North Dakota -- 43%; Montana -- 32%; South Dakota -- 18% and Wyoming -- 7%. System Supply and Demand -- 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 their 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. In addition, propane distribution services are provided to two small communities, one located in eastern Montana and the other in southwestern North Dakota. These markets are highly seasonal and volumes sold depend on weather patterns. Montana-Dakota is extending natural gas service to 11 north- central South Dakota communities at an estimated cost of $9.0 million. This extension has the potential of adding approximately 1.6 million decatherms (MMdk) to annual natural gas sales. Service to seven communities is complete, with service to the remaining four communities, as well as surveys to determine feasibility of service in neighboring communities, scheduled for 1994. 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, Retail Natural Gas 1993 1992 1991 1990 1989 and Propane Throughput Mdk (thousands of decatherms) Sales: Residential. . . . . .19,565 17,141 18,904 16,486 17,890 Commercial . . . . . .11,196 9,256 10,865 11,382 13,145 Industrial . . . . . . 386 284 305 410 608 Total Sales. . . . .31,147 26,681 30,074 28,278 31,643 Transportation: Commercial . . . . . . 3,461 3,450 3,582 2,982 2,483 Industrial . . . . . . 9,243 10,292 8,679 8,824 6,838 Total Transporta- tion . . . . . . .12,704 13,742 12,261 11,806 9,321 Total Throughput . . . .43,851 40,423 42,335 40,084 40,964 The Company has been pursuing an aggressive marketing program targeting small and large fleet vehicle owners for the use of compressed natural gas (CNG) as a vehicle fuel. CNG is a more environmentally sound fuel than gasoline, dramatically reducing carbon monoxide and other emissions, and costs substantially less than gasoline. Currently the Company has 13 refueling stations providing CNG to over 500 vehicles. In 1993, Montana-Dakota's throughput of CNG was 19 Mdk or the equivalent of approximately 158,000 gallons of gasoline. In recent years, Montana-Dakota has obtained the majority of its annual natural gas requirements from Williston Basin, with the balance being provided by various producers under firm contracts. However, commensurate with Williston Basin's unbundling of its various services as a result of its implementation of the FERC's Order 636 on November 1, 1993, as further described under "Interstate Natural Gas Pipeline Operations and Property (Williston Basin)" Montana-Dakota elected to acquire approximately 88 percent of its system requirements directly from producers and processors with the balance still being provided by Williston Basin. Such natural gas is supplied under firm contracts varying in length from less than one year to over five years and is transported under firm transportation agreements by Williston Basin and, with respect to Montana-Dakota's system expansion into north-central South Dakota, by South Dakota Intrastate Pipeline Company. Montana-Dakota has also contracted with Williston Basin to provide firm storage services which enable Montana-Dakota to purchase natural gas at more nearly uniform daily volumes throughout the year and thus, meet winter peak requirements at lower costs. Montana-Dakota has implemented an integrated resource plan which is used in planning for a reliable future supply of natural gas which will coincide with anticipated customer demand. 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. Other supply alternatives being evaluated are the installation of peak shaving facilities, the acquisition of storage gas inventories to meet peak demand and the interconnection with other pipelines. On the demand side, Montana-Dakota is evaluating the use of various conservation programs which include energy audits, weatherization programs and incentives for the installation of high efficiency appliances such as boilers, furnaces and water heaters. The development and evaluation of other economically feasible strategic marketing programs continues. Regulatory Matters -- Montana-Dakota's retail natural gas rate schedules contain clauses permitting adjustments in rates based upon changes in natural gas commodity, transportation and storage costs. The various commissions' current regulatory practices allow Montana-Dakota to recover increases or refund decreases in such costs within 24 months from the time such changes occur. In July 1992, Montana-Dakota requested the NDPSC to implement a gas weather normalization adjustment mechanism in November 1992. In October 1992, the NDPSC disallowed the adjustment mechanism. Montana-Dakota requested reconsideration of this matter, which was granted by the NDPSC in December 1992. A continuance was granted until such time as a general natural gas rate case should be filed. Montana-Dakota filed a general natural gas rate case on July 30, 1993, requesting increased revenues of $1.8 million, or 2.8 percent. On November 23, 1993, Montana-Dakota and the NDPSC reached a settlement of this proceeding which provides for additional revenues of approximately $1.1 million, or 57 percent of the original amount requested, effective December 1, 1993. In order to reach a favorable settlement and place increased rates into effect this heating season, the implementation of the weather normalization adjustment mechanism was omitted from the settlement. Montana-Dakota anticipates requesting the implementation of this mechanism in a future proceeding. On June 30, 1993, Montana-Dakota filed a general natural gas rate case with the WPSC requesting increased revenues of approximately $430,000, or 4.3 percent. Montana-Dakota and the WPSC reached a settlement of this proceeding on November 30, 1993, providing for an increase equal to Montana-Dakota's request effective December 1, 1993. Montana-Dakota filed a general natural gas rate case with the South Dakota Public Utilities Commission (SDPUC) on September 3, 1993, requesting increased revenues of approximately $1.3 million, or 5 percent. On January 19, 1994, Montana-Dakota and the SDPUC reached a settlement of this proceeding which provides for additional revenues of $605,000, or 47 percent of the original amount requested, effective January 19, 1994. However, the issue related to Montana-Dakota's request that the SDPUC authorize accrual accounting for postretirement benefits, representing 26 percent of the amount originally requested, was deferred and commission hearings are scheduled for March 1994. In December 1992, the MPSC issued an order on certain purchased gas cost adjustment filings covering the period December 1989 through November 1992, permitting an interim increase in natural gas rates effective as of the date of its order. However, the MPSC deferred ruling on the prudency of Montana-Dakota's decision not to implement its 1990 and 1991 gas supply conversion options. The MPSC issued a procedural schedule for disposition of this deferred issue in mid-1993, but later suspended this matter until a future date. In August 1993, the MPSC issued an interim order in a purchased gas cost adjustment filing made in April 1993, permitting an interim increase in natural gas rates effective as of the date of the order. Capital Requirements -- In 1993, Montana-Dakota expended $15.0 million for natural gas and propane distribution facilities and currently anticipates expending approximately $12.4 million, $10.4 million and $11.3 million in 1994, 1995 and 1996, 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 may be found with regard to the issues described below, Montana-Dakota believes it is in substantial compliance with those regulations. Montana-Dakota and Williston Basin discovered polychlorinated biphenyls (PCBs) in portions of their natural gas systems and informed the EPA in January 1991. Montana-Dakota and Williston Basin believe the PCBs entered the system from a valve sealant. Both Montana-Dakota and Williston Basin have initiated testing, monitoring and remediation procedures, in accordance with applicable regulations and the work plan submitted to the EPA and the appropriate state agencies. Costs incurred by Montana-Dakota and Williston Basin through December 31, 1993, to address this situation aggregated approximately $720,000. These costs are related to the testing being performed, and the costs to remove, dispose of and replace certain property found to be contaminated. On the basis of findings to date, Montana-Dakota and Williston Basin estimate that future environmental assessment and remediation costs that will be incurred range from $3 million to $15 million. This estimate depends upon a number of assumptions concerning the scope of remediation that will be required at certain locations, the cost of remedial measures to be undertaken and the time period over which the remedial measures are implemented. In a separate action, Montana-Dakota and Williston Basin filed suit in Montana State Court, Yellowstone County, in January 1991, against Rockwell International Corporation, manufacturer of the valve sealant, to recover any costs which may be associated with the presence of PCBs in the system, including a remediation program. On January 31, 1994, Montana-Dakota, Williston Basin and Rockwell reached a settlement which terminated this litigation. Pursuant to the terms of the settlement, Rockwell will reimburse Montana-Dakota and Williston Basin for a portion of certain remediation costs incurred or expected to be incurred. In addition, both Montana-Dakota and Williston Basin consider unreimbursed environmental remediation costs and costs associated with compliance with environmental standards to be recoverable through rates, since they are prudent costs incurred in the ordinary course of business and, accordingly, have sought and will continue to seek recovery of such costs through rate filings. Although no assurances can be given, based on the estimated cost of the remediation program and the expected recovery of most of these costs from third parties or ratepayers, Montana-Dakota and Williston Basin believe that the ultimate costs related to these matters will not be material to Montana-Dakota's or Williston Basin's financial position or results of operations. In June 1990, Montana-Dakota was notified by the EPA that it and several others were named as Potentially Responsible Parties (PRPs) in connection with the cleanup of pollution at a landfill site located in Minot, North Dakota. An informational meeting was held on January 20, 1993, between the EPA and the PRPs outlining the EPA's proposed remedy and the settlement process. On June 21, 1993, the EPA issued its decision on the selected remediation to be performed at the site. Based on the EPA's proposed remediation plan, current estimates of the total cleanup costs for all parties, including oversight costs, at this site range from approximately $3.7 million to $4.8 million. Montana-Dakota believes that it was not a material contributor to this contamination and, therefore, further believes that its share of the liability for such cleanup will not have a material effect on its results of operations. CENTENNIAL ENERGY HOLDINGS, INC. INTERSTATE NATURAL GAS TRANSMISSION OPERATIONS AND PROPERTY (WILLISTON BASIN) General -- Williston Basin owns and operates approximately 3,800 miles of transmission, gathering and storage lines and 25 compressor stations located in the states of North Dakota, South Dakota, Montana and Wyoming and has interconnections with seven pipelines in Wyoming, Montana and North Dakota. Through three underground storage facilities 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 readily 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. At December 31, 1993, the net interstate natural gas transmission plant investment was approximately $159.9 million, of which approximately $76.8 million is subject to certain purchase money mortgages payable to the Company. 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, wholesale sales, transportation and related storage operations. In recent years, the business operations of Williston Basin, as well as the natural gas pipeline industry in general, have undergone substantial transformation. This transformation reflects significant changes in both natural gas markets and Federal regulatory policies. In the past, Williston Basin had served primarily as a natural gas merchant, purchasing supplies under long-term contracts with numerous producers and reselling to local distribution companies under long-term service agreements. NGA regulatory policies related to both pipeline rates and conditions of service stressed stability of gas supplies and service, and the reasonable opportunity for recovery by pipelines of their costs of providing that service. Beginning in the 1980's, changes in natural gas markets, which resulted from increased supplies and reduced demand, and changing regulatory policies, required Williston Basin to revise long-term service arrangements in order to respond to a more competitive, price-sensitive marketplace. This situation was compounded by the advent of open-access transportation, which served to foster competition among gas suppliers. Williston Basin continuously modified its business practices in order to respond to this increasingly competitive business environment and to regulatory uncertainties. In April 1992, the FERC issued Order 636, which requires fundamental changes in the way natural gas pipelines do business. See "Regulatory Matters and Revenues Subject to Refund -- Order 636" for a further discussion on Williston Basin's implementation of Order 636. For additional information regarding Williston Basin's sales and transportation for 1991 through 1993, see Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations". System Demand -- In recent years, Williston Basin has provided the majority of Montana-Dakota's annual natural gas requirements. However, upon Williston Basin's implementation of Order 636, Montana-Dakota elected to acquire substantially all of its system requirements directly from processors and other producers. Williston Basin transports all such natural gas for Montana-Dakota under a firm transportation agreement. In addition, Montana-Dakota has contracted with Williston Basin to provide firm storage services to facilitate meeting Montana-Dakota's winter peak requirements. In February 1991, Williston Basin and Northern States Power Company (NSP) reached an agreement providing for the firm transportation delivery by Williston Basin to NSP of 8,000 Mcf of natural gas per day. Construction by Williston Basin of an interconnection to NSP was completed in November 1992. This interconnection also provides Williston Basin the added capability of up to 15,000 Mcf per day of interruptible transportation. During 1993, 2.3 million decatherms (MMdk) of natural gas was transported through this interconnection. Certain of Williston Basin's transportation customers with large regional supplies of natural gas have the potential of bypassing Williston Basin by accessing other pipelines' facilities. In 1991, two of Williston Basin's major transportation customers, Koch Hydrocarbon Company (Koch) and Amerada Hess Corporation (Amerada) indicated their intent to construct pipeline facilities in North Dakota bypassing Williston Basin's pipeline system. Both Koch and Amerada filed applications with the FERC requesting exemption from the FERC's jurisdiction for these proposed facilities, which the FERC approved. Williston Basin requested rehearing of these decisions, which the FERC denied and, as a result, Williston Basin appealed the orders to the U.S. Court of Appeals for the D.C. Circuit. Subsequently, applications were filed by both Koch and Amerada with the NDPSC requesting approval of the siting corridors for these facilities. Amerada's and Koch's requests were approved by the NDPSC in August 1992. Construction of Amerada's line was completed in late 1992, with Koch's line being completed in early 1993. On August 12 and August 26, 1993, the Court remanded Koch's and Amerada's applications, respectively, back to the FERC at the FERC's request. Subsequently, the FERC vacated its prior order which exempted Koch's facilities from the FERC's jurisdiction, stating that such order was moot because Koch had not constructed the facilities as originally requested. The FERC is continuing to evaluate its order regarding Amerada's facilities. As a result of these bypasses, Williston Basin received 11.3 MMdk less natural gas for transportation in 1993 than in 1992. 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 certificate authorizes a company-owned gas inventory of up to 180 billion cubic feet on an annual average basis inclusive of recoverable and nonrecoverable native gas. Williston Basin's storage facilities enable its customers to purchase natural gas at more nearly uniform daily volumes throughout the year and thus, facilitate meeting winter peak requirements at lower costs. On April 1, 1993, Williston Basin filed an application with the FERC for authority to increase its certificated storage withdrawal capacity by 95 MMcf, which the FERC approved on September 20, 1993. This increase will allow Williston Basin to expand and enhance the storage services it offers to its customers. Williston Basin has estimated that $10.4 million will be expended in 1994 related to this enhancement. 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 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 interconnections and could provide substantial future benefits to Williston Basin. In 1993, Williston Basin interconnected its facilities with those of Many Islands Pipeline Ltd., a subsidiary of TransGas Ltd., a Saskatchewan, Canada pipeline. This interconnect, from which Williston Basin began receiving firm transportation gas in January 1994, will provide initial access to up to 10,000 Mcf per day firm Canadian supply with additional opportunities for interruptible volumes. As supported by a study dated January 17, 1994, by Ralph E. Davis Associates, Inc., (an independent firm of petroleum and natural gas engineers) Williston Basin has available 116,476 MMcf of owned gas in producing fields. Pending Litigation -- Koch Hydrocarbon Company (Koch) -- On August 11, 1993, Koch and Williston Basin reached a settlement that terminated the litigation, as previously described in the 1992 Annual Report on Form 10-K and the September 30, 1993 Quarterly Report on Form 10-Q, with respect to all parties. The settlement, as to both the Company and Williston Basin, satisfies all of Koch's claims for the past obligation, releases any claim with respect to obligations up to the present time and terminates any contractual arrangements with respect to the purchase of natural gas between the parties for the future. The settlement thus resolves both the past and the future obligation. In return, Williston Basin agreed to make an immediate cash payment to Koch of $40 million (inclusive of the $32 million awarded by the District Court in October 1991) and to transfer to Koch certain natural gas gathering facilities owned by Williston Basin having a cost, net of accumulated depreciation, of approximately $10.4 million. The Company believes that it is entitled to recover from ratepayers most of the costs that were incurred as a result of this settlement. Since the amount of costs which can ultimately be recovered is subject to regulatory and market uncertainties, the Company has provided reserves which it believes are adequate for any amounts that may not be recovered. Williston Basin expects to recover $8.3 million in settlement costs through its purchased gas cost adjustment recovery mechanism. See "Regulatory Matters and Revenues Subject to Refund" for a discussion of Williston Basin's filings under the FERC's Orders 500 and 636 requesting recovery of the balance of the costs associated with the Koch settlement. KN Energy, Inc. (KN) -- In May 1991, KN, a pipeline for whom Williston Basin transports natural gas, filed suit against Williston Basin in Federal District Court for the District of Montana. KN alleges, in part, that Williston Basin breached its contract with KN by failing to provide priority transportation for KN, and by charging KN transportation rates which were excessive. KN also alleges that Williston Basin is responsible for any take-or-pay costs it may incur as a result of the breach. Although no amount of damages was specified, KN asked the Court to order Williston Basin to reimburse KN for damages and certain other costs it has incurred along with requiring specific performance pursuant to the contract. Williston Basin filed a motion for summary judgment with the Court in August 1992, requesting that the Court dismiss KN's suit on the basis that these matters are more appropriate for FERC resolution. In September 1992, the Court denied Williston Basin's motion for summary judgment, but suspended the proceedings before it and referred these matters to the FERC. If the FERC is not able to ultimately resolve this dispute, both KN and Williston Basin can request reconsideration by the Court at that time. As of the present time, KN has not requested further action by the FERC. Although no assurances can be provided, based on previous FERC decisions, Williston Basin believes that the ultimate outcome of this matter will not be material to its financial position or results of operations. Regulatory Matters and Revenues Subject to Refund -- General Rate Proceedings -- Williston Basin has pending two general natural gas rate change applications filed in 1989 and 1992 and has implemented these changed rates subject to refund. Williston Basin is awaiting final orders from the FERC. Reserves have been provided for a portion of the revenues collected subject to refund with respect to pending regulatory proceedings and for the recovery of certain producer settlement buy-out/buy-down costs as discussed below 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. Open Access Transportation and Producer Settlement Cost Recovery -- In order to make available the alternate take-or-pay cost recovery mechanism embodied in FERC Order 500 under the NGA, Williston Basin, in March 1989, filed an application with the FERC requesting a blanket certificate to transport natural gas under such authority. Williston Basin also filed proposed tariff provisions to govern implementation of the alternate take-or-pay cost recovery mechanism available under the Order 500 series, although a specific election on cost absorption was not specified. In August 1989, Williston Basin received an order from the FERC issuing the requested blanket certificate. Williston Basin filed tariffs for Order 500 transportation services which were accepted by the FERC, subject to the outcome of other proceedings. In June 1990, Williston Basin filed to recover 75 percent of $43.4 million ($32.6 million) in buy-out/buy-down costs under the alternate take-or-pay cost recovery mechanism embodied in Order 500. As permitted under Order 500, Williston Basin elected to recover 25 percent or $10.8 million of such costs through a direct surcharge to its sales customers, substantially all of which has been received, with an equal amount being charged to second quarter 1990 earnings. Williston Basin elected to recover the remaining 50 percent ($21.7 million) through a commodity sales rate surcharge. In July 1990, the FERC issued an order requiring Williston Basin to recalculate its surcharge and apply it to total throughput. Through December 31, 1993, Williston Basin has collected $23.6 million, including interest, of these costs through its commodity sales and transportation rate surcharges. In November 1990, Williston Basin appealed this order to the U.S. Court of Appeals for the D.C. Circuit. Oral argument before the Court was held in November 1991. In July 1992, the Court issued its order denying Williston Basin's appeal and remanding certain aspects of the case to the FERC. On May 6, 1993, the FERC issued an order on those issues remanded by the Court. The principal issue addressed by this order involved the exemption of one of Williston Basin's major transportation customers from the assessment of take-or-pay surcharges. Williston Basin made a filing seeking authority to reallocate these costs to its other customers, which the FERC approved. On August 26, 1993, Williston Basin filed to recover 75 percent of $28.7 million ($21.5 million) in buy-out/buy-down costs paid to Koch as part of a lawsuit settlement under the alternate take-or- pay cost recovery mechanism embodied in Order 500. As permitted under Order 500, Williston Basin elected to recover 25 percent or $7.2 million of such costs through a direct surcharge to sales customers, substantially all of which has been received. In addition, through reserves previously provided, Williston Basin has absorbed an equal amount. Williston Basin elected to recover the remaining 50 percent ($14.3 million) through a throughput surcharge applicable to both sales and transportation. Williston Basin began collecting these costs, subject to refund, on October 1, 1993, pending the outcome of future hearings in mid-1994. Order 636 -- In April 1992, the FERC issued Order 636, which requires fundamental changes in the way natural gas pipelines do business. Under Order 636, pipelines are required to offer unbundled transportation service, with the transportation customer having the option of purchasing gas from other suppliers. Pipelines are also required to provide "equivalent" transportation services for all customers regardless of whether they are purchasing gas from such pipeline or other suppliers. As a part of Order 636, the FERC acknowledged that incremental costs may be required in the transition to the FERC-mandated service structures. Such costs include facility costs, gas supply contract restructuring and similar costs. Specific references concerning the allowed recovery of such costs are included in the final rule. In addition, Order 636 changes the rate design methodology used for pipeline transportation to the straight fixed variable (SFV) method. Under the SFV approach, all fixed storage and transmission costs, including return on equity and associated taxes, are included in the demand charge (a fixed monthly charge) and all variable costs are recovered through a commodity charge based on volumes transported. Under SFV, pipelines should be able to recover all fixed costs properly allocable to firm transportation regardless of how much gas is actually transported. Also included in Order 636 were guidelines addressing abandonment of services, capacity release and/or assignment of firm capacity rights. In October 1992, Williston Basin filed a revised tariff with the FERC designed to comply with Order 636. The revised tariff reflected the cost allocation and rate design necessary to the unbundling of Williston Basin's current services. The FERC issued an order on February 12, 1993, in which it accepted Williston Basin's filing subject to certain conditions. On March 15, 1993, Williston Basin filed further tariff revisions with the FERC in compliance with the FERC's February 12, 1993, order, and on March 12, 1993, filed for rehearing and/or clarification of other matters raised in the February 12, 1993, order. On May 13, 1993, the FERC issued an order addressing both Williston Basin's rehearing request and its March 15 tariff filing. A significant issue addressed by the FERC's order was a determination that certain natural gas in underground storage which was determined to be excess upon the future implementation of Order 636 must be sold at market prices. The order further required that the profit from such sale be used to offset any transition costs. Williston Basin requested rehearing of this and other issues by the FERC. An appeal was filed by Williston Basin on June 30, 1993, with the U.S. Court of Appeals for the D.C. Circuit related to, among other things, the FERC allowing firm transportation customers flexible receipt and delivery points anywhere on Williston Basin's pipeline system upon implementation of Order 636. On September 17, 1993, the FERC issued its order authorizing Williston Basin's implementation of Order 636 tariffs effective November 1, 1993. As a part of this order, the FERC reversed its May 13, 1993, determination related to the sale of certain natural gas in underground storage and ordered that this storage gas be offered for sale to Williston Basin's customers at its original cost. As a result, any profits which would have been realized on the sale at market prices of this storage gas will not reduce Williston Basin's Order 636 transition costs. Williston Basin requested rehearing of this issue by the FERC on the grounds that requiring the sale of this storage gas at cost results in a confiscation of its assets, which the FERC denied on December 16, 1993. Williston Basin has appealed the FERC's decisions to the U.S. Court of Appeals for the D.C. Circuit. On November 5, 1993, Williston Basin filed with the FERC, pursuant to the provisions of Order 636, revised tariff sheets requesting the recovery of $13.4 million of gas supply realignment transition costs (GSR costs) effective December 1, 1993. The GSR cost recovery being requested reflects costs paid to Koch as part of a lawsuit settlement, as previously described under "Pending Litigation" and does not include other GSR costs, if any, which may be incurred, and future recovery sought, by Williston Basin. This matter is currently pending before the FERC. Montana-Dakota has also filed revised gas cost tariffs with each of its four state regulatory commissions reflecting the effects of Williston Basin's November 1, 1993, implementation of Order 636. In October 1993, all four state regulatory commissions approved the revised tariffs. Although no assurances can be provided, the Company believes that Order 636 will not have a significant effect on its financial position or results of operations. Natural Gas Repurchase Commitment -- The Company has offered for sale since 1984 the 61 MMdk of inventoried natural gas available under a repurchase commitment with Frontier Gas Storage Company, as described in Note 5 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 and not recover any loss on its sale from customers. 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 $3.9 million, $5.8 million and $8.5 million in 1993, 1992 and 1991, respectively. The FERC issued an order in July 1989, ruling on several cost-of-service issues reserved as a part of the 1985 corporate realignment. Addressed as a part of this order were certain rate design issues related to the permissible rates for the transportation of the natural gas held under the repurchase commitment. The issue relating to the cost of storing this gas was not decided by that order. As a part of orders issued in August 1990 and May 1991 related to a general rate increase application, the FERC held that storage costs should be allocated to this gas. Williston Basin's July 1991 refund related to a general rate increase application, reflected implementation of the above finding on a prospective basis only. The public service commissions of Montana and South Dakota and the Montana Consumer Counsel protested whether such storage costs should be allocated to the gas prospectively rather than retroactively to May 2, 1986. In October 1991, the FERC issued an order rejecting Williston Basin's compliance filing on the basis that, among other things, Williston Basin is required to allocate storage costs to this gas retroactive to May 2, 1986. Williston Basin requested rehearing of the FERC's order on this issue in November 1991. In February 1992, the FERC issued an order which reversed its October 1991 order and held that such storage costs be allocated to this gas on a prospective basis only, commencing March 6, 1992. A compliance filing was made with the FERC in March 1992, which the FERC approved on and with an effective date beginning May 20, 1992. These storage costs, as initially allocated to the Frontier gas, approximated $2.1 million annually and represent costs which Williston Basin may not recover. The issue regarding the applicability of assessing storage charges to the gas, which was appealed by Williston Basin to the U.S. Court of Appeals for the D.C. Circuit in July 1991, creates additional uncertainty as to the costs associated with holding this gas. In July 1992, the Court, at the FERC's request, returned the proceeding to the FERC for its further consideration. Beginning in October 1992, as a result of increases in natural gas prices, Williston Basin began to sell and transport a portion of the natural gas held under the repurchase commitment. Through December 31, 1993, 12.5 MMdk of this natural gas had been sold and transported by Williston Basin to off-system markets. Williston Basin will continue to aggressively market the remaining 48.3 MMdk of this natural gas as long as market conditions remain favorable. In addition, it will continue to seek long-term sales contracts. Other Information -- Supplementary information with respect to natural gas producing activities is not included herein since the related production is anticipated to recover its equivalent cost of service. However, as a part of the corporate realignment in January 1985, the Company agreed to adjust retail rates so as to limit flow-through of prices higher than cost of service to 50 percent of the excess. Based on the terms of the Settlement, refunds for the 1991 and 1992 production years aggregating $1.0 million and $176,000, respectively, were made in the ensuing year. Estimated reserves associated with this gas are 116,476 MMcf. The unamortized capital costs related to these reserves are approximately $7.9 million at December 31, 1993. In March and May 1993, Williston Basin was directed by the United States Minerals Management Service (MMS) to pay approximately $3.5 million, plus interest, in claimed royalty underpayments. These royalties are attributable to natural gas production by Williston Basin from federal leases in Montana and North Dakota for the period December 1, 1978, through February 29, 1988. Williston Basin has filed an administrative appeal with the MMS on this issue stating the gas was properly valued for royalty purposes. Williston Basin also believes that the statute of limitations limits this claim. Williston Basin is pursuing these issues before both the MMS and the courts. On December 21, 1993, Williston Basin received from the Montana Department of Revenue (MDR) an assessment claiming additional production taxes due of $3.7 million, plus interest, for 1988 through 1991 production. These claimed taxes result from the MDR's belief that certain natural gas production during the period at issue was not properly valued. Williston Basin does not agree with the MDR and has reached an agreement with the MDR that the appeal process be held in abeyance pending further review. Capital Requirements -- Williston Basin's construction expenditures approximated $5.4 million in 1993, and are estimated to be $19.5 million, $14.6 million and $24.3 million in 1994, 1995 and 1996, respectively. 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. In mid-1992, Williston Basin discovered that several of its natural gas compressor stations had been operating without air quality permits. As a result, in late 1992, applications for permits were filed with the Montana Air Quality Bureau (Bureau), the agency for the state of Montana which regulates air quality. In March 1993, the Bureau cited Williston Basin for operating the compressors without the requisite air quality permits and further alleged excessive emissions by the compressor engines of certain air pollutants, primarily oxides of nitrogen and carbon monoxide. Williston Basin is currently engaged in further testing these air emissions but is currently unable to determine the costs that will be incurred to remedy the situation although such costs are not expected to be material to its financial position or results of operations. MINING AND CONSTRUCTION MATERIALS OPERATIONS AND PROPERTY (KNIFE RIVER) Coal Operations: General -- The Company, through Knife River, is engaged in lignite coal mining operations. Knife River's surface mining operations are located at Beulah and Gascoyne, North Dakota and Savage, Montana. The average annual production from the Beulah, Gascoyne and Savage mines approximates 2.4 million, 2.1 million and 275,000 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, 1993 1992 1991 1990 1989 (In thousands) Tons sold: Montana-Dakota generating stations. . 624 521 618 592 675 Jointly-owned generating stations-- Montana-Dakota's share. . . . 1,034 1,021 953 895 933 Others. . . . . . . . . . . . 3,299 3,259 3,069 2,872 2,982 Industrial and other sales . . 109 112 91 80 157 Total . . . . . . . . . . . . 5,066 4,913 4,731 4,439 4,747 Revenues . . . . . . . . . . . $44,230 $43,770 $41,201 $38,276 $41,643
In recent years, in response to competitive pressures from other mines, Knife River has reduced its coal prices and/or not passed through cost increases which are allowed under its contracts. Although Knife River has contracts in place specifying the selling price of coal, these price concessions are being made in an effort to remain competitive and maximize sales. Ongoing cost containment measures and enhanced mining efficiencies continue to assist Knife River in maintaining its market position. Knife River and Montana-Dakota entered into a five-year coal sales contract for sales made from the Savage Mine to Montana- Dakota's Lewis and Clark Station effective January 1, 1993. This contract stipulates a reduction in the price paid for coal mined in government-owned properties. The reduction is the result of Knife River's success in obtaining a reduction in the federal royalty rate paid. In early 1993, Knife River, together with the Lignite Energy Council, supported the introduction of legislation in North Dakota which would provide severance tax relief for its Gascoyne Mine. Under the legislation, the state will forego its 50 percent share of severance taxes for coal shipped out of state after July 1, 1995, and local political subdivisions are given the option to forego their 35 percent of the tax. The legislation passed both House and Senate with strong support and was signed by the governor. This tax relief will help keep the price of Gascoyne coal competitive. Construction Materials Operations: General -- In May 1992, KRC Aggregate, Inc. (KRC Aggregate), an indirect, wholly-owned subsidiary of Knife River, entered into the sand and gravel business in north-central California through the purchase of certain properties, including mining and processing equipment. These operations, located near Lodi, California, surface mine, process and market aggregate products to various customers, including road and housing contractors, tile manufacturers and ready-mix plants, with a market area extending approximately 60 miles from the mine. On April 2, 1993, the assets of Alaska Basic Industries, Inc. (ABI) and its subsidiaries were purchased by KRC Aggregate. ABI is a vertically integrated construction materials business headquartered in Anchorage, Alaska. ABI's nine divisions handle the sale of its sand and gravel aggregates and related products such as ready-mixed concrete, asphalt and finished aggregate products. Effective September 1, 1993, KRC Aggregate, purchased the stock of LTM, Incorporated (LTM), Rogue Aggregates, Inc. (Rogue) and Concrete, Inc., construction materials subsidiaries of Terra Industries. Headquartered in Medford, Oregon, LTM and Rogue are vertically integrated construction materials businesses serving southern Oregon markets. Their products include sand and gravel aggregates, ready-mixed concrete, asphalt and finished aggregate products. Concrete, Inc., headquartered in Stockton, California, operates four ready-mix plants in San Joaquin County. These ready- mix plants became part of KRC Aggregate's Lodi, California operations. Sales volumes and revenues for the construction materials operations during 1992 and 1993 were as follows: Years Ended December 31, (In thousands) 1993 1992 Aggregates (tons). . . . . . . . . . . . 2,391 263 Ready-mixed concrete (cubic yards) . . . 157 --- Asphalt (tons) . . . . . . . . . . . . . 141 --- Revenues . . . . . . . . . . . . . . . . $ 46,167 $ 1,262 Consolidated Mining and Construction Materials Operations: Capital Requirements -- Consolidated construction expenditures for Knife River approximated $46.5 million in 1993, including amounts related to the acquisition by KRC Aggregate of ABI, LTM, Rogue and Concrete, Inc. Construction expenditures are estimated to be $4.5 million in 1994, $5.6 million in 1995 and $7.6 million in 1996. Such expenditures are primarily for replacement of existing equipment, mine-site improvements, lease acquisitions and further development of the Beulah mine. Knife River continues to seek out additional mining opportunities. This includes not only identifying possibilities for alternate uses of lignite coal but also investigating the acquisition of other surface mining properties, particularly those relating to sand and gravel aggregates and related products such as ready-mixed concrete, asphalt and various finished aggregate processes. Any capital expenditures related to other potential mining acquisitions are not reflected in the above 1994-1996 capital needs. Environmental Matters -- Knife River's mining and construction materials operations are subject to regulation customary for surface mining operations, including federal, state and local environmental and reclamation regulations. Knife River believes that these operations are in substantial compliance with those regulations. One of Knife River's major coal customers, the Big Stone Station, will be required to comply with the Clean Air Act emission standards by the year 2000. Alternatives available to this customer include installation of a sulfur scrubber, switching to lower sulfur coal, using processed or "clean" coal, or fuel blending. Some of the alternatives could have a significant adverse effect on Knife River's coal operations including its ability to extend the existing coal contract beyond its 1995 expiration date. Knife River continues its involvement in lignite research with emphasis placed upon enhancement of lignite coal as a boiler fuel. In addition, Knife River continues to monitor progress on clean coal technologies. Reserve Information -- As of December 31, 1993, Knife River had under ownership or lease, reserves of approximately 231 million tons of recoverable lignite coal at present mining locations. Such reserves estimates were prepared by Paul Weir Company Incorporated, independent mining engineers and geologists, in a report dated January 20, 1989, and have been adjusted for 1989 through 1993 production and the relinquishment of federal and fee coal contracts at two mine sites. Knife River estimates that approximately 109 million tons of its reserves will be needed to supply all of Montana-Dakota's existing generating stations for the expected lives of those stations and to fulfill the existing commitments of Knife River for sales to third parties. As of December 31, 1993, the combined construction materials operations had under ownership approximately 74 million tons of recoverable aggregate reserves. OIL AND NATURAL GAS OPERATIONS AND PROPERTY (FIDELITY OIL) General -- The Company, through Fidelity Oil, is involved in the acquisition, exploration, development and production of oil and natural gas properties. Fidelity Oil has had oil and natural gas interests since 1951 when an operating agreement (Agreement) relating to its net proceeds acreage interests was signed with Shell Western E&P, Inc. (Shell). Beginning in 1986, Fidelity Oil undertook a growth and development strategy focused on programs directed at the acquisition of producing properties, exploration and development. Fidelity Oil, through its net proceeds interests, owns in fee or holds oil and natural gas leases and operating rights applicable to the deep rights (below 2,000 feet) in the Cedar Creek Anticline in southeastern Montana. Pursuant to the Agreement, Shell, as operator, controls all development, production, operations and marketing applicable to such acreage. As a net proceeds interest owner, Fidelity Oil is entitled to proceeds only when a particular unit has reached payout status. Fidelity Oil undertakes ventures, through a series of working-interest agreements with several different partners, that vary from the acquisition of producing properties with potential development opportunities to exploration and are located in the western United States, offshore in the Gulf of Mexico and in Canada. In these ventures, Fidelity Oil shares revenues and expenses from the development of specified properties in proportion to its investments. 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 net proceeds and working interests for 1993, 1992 and 1991 are as follows: 1993 1992 1991 Oil: Production (000's of barrels). . . . . 1,500 1,500 1,500 Average sales price. . . . . . . . . . $14.84 $16.74 $19.90 Natural Gas: Production (MMcf). . . . . . . . . . . 8,800 5,000 2,600 Average sales price. . . . . . . . . . $1.86 $1.53 $1.48 Production costs, including taxes, per net equivalent barrel. . . . . . . $3.98 $4.81 $5.86 Well and Acreage Information -- Fidelity Oil's gross and net productive well counts and gross and net developed and undeveloped acreage for the net proceeds and working interests at December 31, 1993, are as follows: Gross Net Productive Wells: Oil. . . . . . . . . . . . . . . . . . . . 3,530 129 Natural Gas . . . . . . . . . . . . . . . 627 29 Total. . . . . . . . . . . . . . . . . . 4,157 158 Developed Acreage (000's). . . . . . . . . . 562 75 Undeveloped Acreage (000's). . . . . . . . . 683 52 Exploratory and Development Wells -- The following table shows the results of oil and natural gas wells drilled and tested during 1993, 1992 and 1991:
Net Exploratory Net Development Productive Dry Holes Total Productive Dry Holes Total Total 1993 2 2 4 5 1 6 10 1992 --- 4 4 2 1 3 7 1991 2 5 7 8 3 11 18
At December 31, 1993, there were two exploratory wells and one development well in the process of drilling. Capital Requirements -- The following summary reflects capital expenditures, including those not subject to amortization, related to oil and natural gas activities for the years 1993, 1992 and 1991: 1993 1992 1991 (In thousands) Acquisitions . . . . . . . . . . . . . $ 9,296 $ 9,976 $ 4,667 Exploration. . . . . . . . . . . . . . 7,787 11,074 7,781 Development. . . . . . . . . . . . . . 7,836 4,715 9,824 Total Capital Expenditures . . . . . $24,919 $25,765 $22,272 Fidelity Oil plans additional commitments to oil and gas investments and has budgeted approximately $30 million for each of the years 1994 through 1996 for such activities. Such investments are expected to be financed with a combination of funds on hand at December 31, 1993, funds to be internally generated and the $20 million currently available under Fidelity Oil's long-term financing arrangements, $1.5 million of which was outstanding at December 31, 1993. Reserve Information -- Fidelity Oil's recoverable proved developed and undeveloped oil and natural gas reserves approximated 11.2 million barrels and 50.3 Bcf, respectively, at December 31, 1993. Of these amounts, 8.3 million barrels and 2.0 Bcf, as supported by a report dated January 10, 1994, prepared by Ralph E. Davis Associates, Inc., an independent firm of petroleum and natural gas engineers, were related to its properties located in the Cedar Creek Anticline in southeastern Montana. For additional information related to Fidelity Oil's oil and natural gas interests, see Note 18 of Notes to Consolidated Financial Statements. ITEM 3. LEGAL PROCEEDINGS Williston Basin has been named as a defendant in a legal action primarily related to its transportation services. Such suit was filed by KN as described under "Pending Litigation". Williston Basin's assessment of this proceeding is included in the description 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 1993. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS MDU Resources Group, Inc. common stock is listed on the New York Stock Exchange and uses the symbol "MDU". The price range of the Company's common stock as reported by the Wall Street Journal composite tape during 1993 and 1992 and dividends declared thereon were as follows: Common Common Common Stock Stock Price Stock Price Dividends (High) (Low) Per Share 1993 First Quarter . . . . . . . . $29 1/4 $25 7/8 $ .37 Second Quarter. . . . . . . . 32 1/2 29 .37 Third Quarter . . . . . . . . 32 29 3/4 .39 Fourth Quarter. . . . . . . . 33 1/8 30 1/2 .39 $1.52 1992 First Quarter . . . . . . . . $25 3/4 $23 1/4 $ .36 Second Quarter. . . . . . . . 26 7/8 21 7/8 .36 Third Quarter . . . . . . . . 25 1/2 23 7/8 .37 Fourth Quarter. . . . . . . . 26 3/4 25 .37 $1.46 As of December 31, 1993, the Company's common stock was held by approximately 15,100 stockholders. ITEM 6. SELECTED FINANCIAL DATA Reference is made to selected Financial Data on pages 52 and 53 of the Company's Annual Report which is incorporated herein by reference. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview The following table (in millions of dollars) summarizes the contribution to consolidated earnings by each of the Company's businesses. Years ended December 31, Business 1993 1992 1991 Utility -- Electric . . . . . . . . . . . . $12.6 $13.3 $15.3 Natural gas. . . . . . . . . . . 1.2 1.4 3.6 13.8 14.7 18.9 Natural gas transmission . . . . . 4.7 3.5 0.5 Mining and construction materials. . . . . . . . . . . . 12.4 10.7 9.8 Oil and natural gas production . . 7.1 5.7 8.0 Earnings on common stock . . . . . $38.0 $34.6 $37.2 Earnings per common share. . . . . $2.00 $1.82 $1.96 Return on average common equity. . 12.3% 11.6% 12.7% Earnings information presented in this table and in the following discussion is before the $8.9 million ($5.5 million after-tax) cumulative effect of an accounting change. See Note 2 of Notes to Consolidated Financial Statements for a further discussion of this accounting change. 1993 compared to 1992 Consolidated earnings for 1993 are up $3.4 million when compared to 1992. The improvement is attributable to increased earnings from the natural gas transmission, mining and construction materials, and oil and natural gas production businesses, partially offset by a slight decrease in utility earnings. The reasons for such changes are described in the "1993 compared to 1992" discussions which follow. 1992 compared to 1991 Consolidated earnings for 1992 are down $2.6 million from the $37.2 million earned in 1991. The decline was the result of decreased earnings in the utility and oil and natural gas production businesses, partially offset by increased natural gas transmission and mining and construction materials earnings. The reasons for such changes are described in the "1992 compared to 1991" discussions which follow. ________________________________ Reference should be made to Items 1 and 2 -- "Business and Properties - - Interstate Natural Gas Transmission Operations and Property" and Notes 3, 4 and 5 of Notes to Consolidated Financial Statements for information pertinent to pending litigation, regulatory matters and revenues subject to refund and a natural gas repurchase commitment. 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. Certain reclassifications have been made in the following statistics for 1992 and 1991 to conform to the 1993 presentation. Such reclassifications had no effect on net income or common stockholders' investment as previously reported. Montana-Dakota -- Electric Operations Years ended December 31, 1993* 1992 1991 Operating revenues . . . . . . . . $131.1 $123.9 $128.7 Fuel and purchased power . . . . . 41.3 37.9 38.4 Operation and maintenance expenses . . . . . . . . . . . . 37.4 34.2 33.7 Operating income . . . . . . . . . 30.5 30.2 34.6 Retail sales (kWh) . . . . . . . . 1,893.7 1,829.9 1,877.6 Power deliveries to MAPP (kWh) . . 511.0 352.6 331.3 Cost of fuel and purchased power per kWh. . . . . . . . . . $ .016 $ .016 $ .016 Montana-Dakota -- Natural Gas Distribution Operations Years ended December 31, 1993* 1992 1991 Operating revenues: Sales. . . . . . . . . . . . . . $151.7 $123.8 $134.4 Transportation & other . . . . . 4.3 4.4 4.2 Purchased natural gas sold . . . . 114.0 89.5 98.3 Operation and maintenance expenses . . . . . . . . . . . . 28.6 26.0 23.8 Operating income . . . . . . . . . 4.7 4.5 8.5 Volumes (dk): Sales. . . . . . . . . . . . . . 31.2 26.7 30.1 Transportation . . . . . . . . . 12.7 13.7 12.2 Total throughput . . . . . . . . . 43.9 40.4 42.3 Degree days (% of normal). . . . . 105.5% 87.1% 97.9% Cost of natural gas per dk . . . . $ 3.66 $ 3.35 $ 3.27 *See Note 2 of Notes to Consolidated Financial Statements for a discussion of an accounting change to reflect unbilled revenues. Williston Basin Years ended December 31, 1993 1992 1991 Operating revenues: Sales for resale. . . . . . . . . $51.3* $63.5* $78.8* Transportation & other. . . . . . 40.0* 35.5* 37.2* Purchased natural gas sold . . . . 20.6 33.6 45.3 Operation and maintenance expenses . . . . . . . . . . . . 39.0** 33.0** 39.6** Operating income . . . . . . . . . 20.1 21.3 19.9 Volumes (dk): Sales for resale: Montana-Dakota. . . . . . . . . 13.0 16.5 19.3 Other . . . . . . . . . . . . . .2 .3 .3 Transportation: Montana-Dakota. . . . . . . . . 27.3 24.9 22.1 Other . . . . . . . . . . . . . 32.1 39.6 31.8 Total throughput . . . . . . . . . 72.6 81.3 73.5 Cost of natural gas per dk . . . . $1.78 $1.91 $2.07 _________________________________ * Includes recovery of deferred natural gas contract buy-out/buy-down costs. . . . . $13.0 $ 5.8 $ 6.5 ** Includes amortization of deferred natural gas contract buy-out/buy-down costs. . . . . $11.8 $ 6.2 $ 6.6 Knife River Years ended December 31, 1993 1992 1991 Operating revenues: Coal. . . . . . . . . . . . . . . $44.2 $43.8 $41.2 Construction materials. . . . . . 46.2 1.2 --- Operation and maintenance expenses . . . . . . . . . . . . 59.6 21.2 20.2 Reclamation expense. . . . . . . . 3.1 3.0 2.8 Severance taxes. . . . . . . . . . 4.4 4.3 4.2 Operating income . . . . . . . . . 17.0 11.5 9.7 Sales (000's): Coal (tons) . . . . . . . . . . . 5,066 4,913 4,731 Aggregates (tons) . . . . . . . . 2,391 263 --- Ready-mixed concrete (cubic yards) . . . . . . . . . 157 --- --- Asphalt (tons). . . . . . . . . . 141 --- --- Fidelity Oil Years ended December 31, 1993 1992 1991 Operating revenues . . . . . . . . $39.1 $33.8 $33.9 Operation and maintenance expenses. . . . . . . . . . . . . 11.6 12.0 11.8 Depreciation, depletion and amortization. . . . . . . . . . . 12.0 8.8 6.0 Operating income . . . . . . . . . 11.8 9.5 12.6 Production (000's): Oil (barrels) . . . . . . . . . 1,497 1,531 1,491 Natural gas (Mcf). . . . . . . . 8,817 5,024 2,565 Average sales price: Oil (per barrel) . . . . . . . . $14.84 $16.74 $19.90 Natural gas (per Mcf). . . . . . 1.86 1.53 1.48 1993 compared to 1992 Montana-Dakota--Electric Operations Operating income for the electric business increased due to an improvement in retail sales to residential and commercial markets, primarily the result of colder weather in the first quarter of 1993 and the addition of nearly 540 customers. Also, improving operating income was an increase in deliveries into the MAPP, the result of water conservation efforts by hydroelectric generators and the temporary shutdown of a nuclear generating station in Iowa. Increased fuel and purchased power costs, largely higher demand charges associated with the purchase of an additional five megawatts of firm capacity through a participation power contract partially offset the improvement in operating income. Higher operation and maintenance expenses also negatively affected operating income. Employee benefit-related costs increased operation expense while higher costs associated with repairs made at the Heskett, Big Stone and Coyote stations accounted for the increase in maintenance expense. Earnings from this business unit declined as a result of a decrease in Other Income--Net, reflecting the on-going effects of adopting SFAS No. 106, and increased federal income taxes. A decrease in interest expense due to lower interest rates stemming from long-term debt refinancing in 1992 and lower average short-term borrowings and interest rates, and the aforementioned operating income improvement, somewhat offset the earnings decline. Montana-Dakota--Natural Gas Distribution Operations Sales increases of 4.5 MMdk or $3.6 million, due to significantly colder weather than 1992 and the addition of over 3,500 residential and commercial customers, improved operating income for the natural gas distribution business. However, partially offsetting this improvement were the 1992 refinement of the estimated amount of delivered but unbilled natural gas volumes and increased operation and depreciation expenses. Employee benefit-related costs and distribution and sales expenses related to the system expansion into north-central South Dakota accounted for the majority of the operation expense increase. A Wyoming rate decrease effective in the second quarter of 1992 also reduced the operating income improvement. Gas distribution earnings decreased due to higher financing costs related to increased capital expenditures and carrying charges being accrued on natural gas costs refundable through rate adjustments, offset in part by interest savings resulting from 1992 long-term debt refinancing. The aforementioned operating income change and increased Other Income--Net, primarily due to the return being earned on deferred storage costs and increased interest income earned on natural gas costs recoverable through rate adjustments in Montana, reduced the earnings decline. Williston Basin Operating income declined at the natural gas transmission business as a result of decreased transportation volumes reflecting the effects of bypasses by two major transportation customers. Partially offsetting the effects of these bypasses were the increased movement of 3.4 MMdk of natural gas held under the repurchase commitment, due to favorable natural gas prices, and higher volumes transported on the November 1992 interconnection with NSP (1.8 MMdk), although at lower average rates than those replaced. Operating income was also negatively affected by the delay in the implementation of Order 636 until November 1, 1993. See Items 1 and 2 for Williston Basin for further discussions on the implementation of Order 636. Operation expenses increased slightly due to additional reserves related to the Koch settlement, increased transmission expenses and higher employee benefit-related costs. Largely offsetting the increased operation expenses are lower contract restructuring amortizations, an out-of-period adjustment to take-or-pay surcharge amortizations and a 1992 accrual for retroactive company production royalties. An adjustment to regulatory reserves reflected in operating revenues offset the effects of the additional reserves provided for the Koch settlement. Maintenance expenses increased as a result of compressor overhauls at several compressor station facilities. A weather-related sales improvement of 3.3 MMdk, or $2.8 million, combined with increased general rates implemented in November 1992, partially offset the operating income decline. Income from company production improved due to increased production, but at lower average prices. Earnings for this business unit increased due to reduced interest expense on long-term debt, the result of debt refinancing in mid-1993, and lower carrying costs associated with the natural gas repurchase commitment, primarily the result of both lower borrowings and decreased average rates, offset in part by the decline in operating income discussed above. Knife River Operating income increased due to sales from the newly acquired Alaskan and Oregon construction materials businesses and an improvement in coal tons sold at all mines, mainly the result of increased demand by electric generation customers. Lower selling prices at the Gascoyne Mine, effective June 1, 1992, following an amendment to the current coal supply agreement, partially offset the operating income increase. An increase in operating expenses resulting from the newly acquired construction materials businesses and a volume-related increase in coal operating expenses, combined with the accrual of SFAS No. 106 costs and increased stripping expense at the Beulah mine, due to higher overburden removal costs, also reduced operating income. Earnings increased due to the above-described operating income improvement, offset in part by reduced investment income (included in Other Income--Net), primarily resulting from lower investable funds due to the 1993 acquisitions and lower earned returns, and increased federal income taxes. Fidelity Oil Operating income for the oil and natural gas production business increased as a result of higher natural gas production and prices. In addition, decreased operation and maintenance expenses per equivalent barrel were somewhat offset by volume-related increases in such costs. Partially offsetting the operating income improvement was a decline in oil production and prices and increased depreciation, depletion and amortization, reflecting both increased production and higher rates. The aforementioned increase in operating income was further improved by the realization of certain investment gains resulting in the earnings improvement for this business. Increased interest expense, stemming from both higher average borrowings and rates, and increased federal income taxes, somewhat reduced earnings. 1992 compared to 1991 Montana-Dakota -- Electric Operations The decline in operating income was due to reduced residential and commercial sales resulting primarily from warmer winter weather combined with a cooler summer than that experienced a year ago. An increase in deliveries into the MAPP, primarily in the fourth quarter, was more than offset by the decline in the average price. The fourth quarter increase in deliveries into the MAPP reflects water conservation efforts by hydroelectric generators. The discounting of sales prices necessitated by a weak wholesale market contributed to the price decline experienced for sales to the MAPP. Higher demand charges associated with the purchase of firm capacity through a participation power contract and an increase in operation expense, primarily payroll and benefit-related, also reduced operating income. The demand charge increase results from the additional purchase of 5 megawatts of firm capacity which began in May 1992 and the passthrough of costs associated with a periodic maintenance outage. Partially mitigating the operating income decline was an increase in large industrial sales, lower depreciation expense and a reduction in maintenance expense reflecting the impact of 1991 maintenance outages at the Heskett and Coyote stations. Earnings from this business unit decreased for the reasons discussed above, partially offset by reduced interest expense, the result of certain bond refinancings in the second and fourth quarter of 1991 and the second quarter of 1992 offset in part by increased average borrowings under lines of credit. Montana-Dakota -- Gas Distribution Operations A sales decline of 2.4 MMdk or $2.0 million, related to significantly warmer first quarter weather than in 1991, the refinement of the estimated amount of delivered but unbilled natural gas volumes and an increase in operation expenses, largely payroll and benefit-related costs, were the primary contributors to the operating income decline. The addition of over 2,400 residential and commercial customers mitigated in part the sales decline. Transportation volumes increased largely due to the addition of a large industrial customer in the second quarter of 1992, although at discounted rates, and the conversion of a principal customer from firm commercial sales to transportation. A North Dakota rate increase, which was placed into effect in the third quarter of 1991, partially mitigated the operating income decline. Gas distribution earnings decreased for the reasons discussed above offset in part by decreased interest expense related to carrying charges being accrued on natural gas costs refundable through rate adjustments and the effects of the bond refinancings discussed in Electric Operations above. Williston Basin Operating income improved as a result of increased transportation volumes reflecting the movement of 4.4 MMdk of natural gas held under the repurchase commitment, due to favorable natural gas prices. Reduced operation expenses resulting from December 1991 additions to reserves maintained for regulatory and market uncertainties and reduced litigation expenses and contract restructuring amortizations, offset in part by increased payroll and benefit-related costs and the accrual for retroactive company production royalties, also contributed to the increase in operating income. Partially offsetting the operating income increase were decreased weather-related sales of approximately 571 Mdk or $516,000, lower average realized rates on transportation services, due to a higher level of discounted transportation services being used, and decreased company production revenues, the result of both reduced volumes and lower prices. Earnings for this business unit increased as a result of the changes in operating income discussed above, decreased carrying costs associated with the natural gas repurchase commitment, largely due to lower interest rates, and reduced interest expense on revenues being reserved stemming from lower interest rates and lower carrying charges being accrued on natural gas costs refundable through rate adjustments. Decreased interest income related to recoverable natural gas contract litigation settlement costs and higher company-owned production refund accruals somewhat mitigated the earnings improvement. Knife River Increased coal sales at the Beulah mine, primarily due to outages experienced in 1991 by a major electric generation customer, were the primary factor improving operating income. Aggregate sales at the newly acquired construction materials business also added to operating revenues. Decreased coal sales at the Gascoyne and Savage mines due to reduced weather-related demand from electric generating station customers and increased operation and maintenance expenses partially offset the operating income improvement. The increase in operation and maintenance expenses resulted from a volume-related increase in coal operation expenses and first year expenses at the construction materials business offset in part by equipment efficiencies and lower stripping costs due to recovery of third seam coal at the Beulah mine. Mining and construction materials earnings increased for reasons discussed above offset in part by reduced investment income, largely due to lower returns resulting from declining interest rates, and increased corporate development-related costs (both included in Other Income--Net). Fidelity Oil An increase in oil and natural gas production was more than offset by lower average sales prices for oil producing the decline in operating income. A volume-related increase in operating costs related to working interests and increased depreciation, depletion and amortization also reduced operating income. Decreased operating costs associated with the net proceeds interests resulting from cost controls implemented by the operator, somewhat mitigated the operating income decline. Earnings for the oil and natural gas production business decreased as a result of the above changes in operating income and increased interest expense stemming from increased average borrowings. Prospective Information The operating results of the Company's utility and pipeline businesses are significantly influenced by the weather, the general economy of their respective service territories, and the ability to recover costs through the regulatory process. Montana-Dakota is generally allowed to recover through general rates the costs of providing utility services which include fuel and purchased power costs and the cost of natural gas purchased. The electric business utilizes either fuel adjustment clauses or expedited rate filings to recover changes in fuel and purchased power costs in the interim periods. The natural gas business has similar mechanisms in place to pass through the changes in natural gas commodity, transportation and storage costs. Both recovery mechanisms reduce the effect the changes in these costs have on Montana-Dakota's results. See Items 1 and 2 for a further discussion of these items as they apply to Montana-Dakota's operations. In July 1992, Montana-Dakota requested the NDPSC to implement a gas weather normalization adjustment mechanism in November 1992. In October 1992, the NDPSC disallowed the adjustment mechanism. Montana-Dakota requested reconsideration of this matter, which was granted by the NDPSC in December 1992. A continuance was granted until such time as a general natural gas rate case should be filed. Based on a settlement reached with the NDPSC in connection with a general natural gas rate case filed in July 1993, the implementation of the weather normalization adjustment mechanism was omitted from the settlement. See Items 1 and 2 under Montana- Dakota for a further discussion of the weather normalization adjustment mechanism as well as general rate increase applications filed and settlements reached with the NDPSC, SDPUC and WPSC, respectively. Montana-Dakota is extending natural gas service to 11 north central South Dakota communities at an estimated cost of $9.0 million. This extension has the potential of adding approximately 1.6 MMdk to annual natural gas sales. Service to seven communities began in late 1993 with plans to provide service to the remaining four communities, as well as surveys to determine feasibility in neighboring communities, scheduled for 1994. See Items 1 and 2 for both Montana-Dakota and Williston Basin for additional information related to the FERC's Order 636, which requires fundamental changes in the way natural gas pipelines do business. Williston Basin, based on a September 1993, FERC order, implemented Order 636 on November 1, 1993. Although no assurances can be provided, the Company believes that Order 636 will not have a significant effect on its financial position or results of operations. See Items 1 and 2 for Williston Basin for a further discussion on Williston Basin's construction of a 49-mile pipeline in eastern North Dakota and Williston Basin's interconnection in northwestern North Dakota with a Canadian pipeline. Williston Basin continues to evaluate certain opportunities which may exist to increase transportation and storage services through system expansion or interconnections. In late 1992 and early 1993 two major transportation customers, Koch and Amerada, bypassed Williston Basin's transportation system. As a result of these bypasses, Williston Basin received 11.3 MMdk less natural gas for transportation in 1993 than in 1992. See Items 1 and 2 under Williston Basin for a further discussion of these system bypasses. On October 1, 1992, as a result of increases in natural gas prices, Williston Basin began to sell and transport a portion of the natural gas held under the repurchase commitment. Williston Basin will continue to aggressively market this natural gas as long as market conditions remain favorable. In addition, it will continue to seek long-term sales contracts. See Items 1 and 2 under Williston Basin for additional information on the natural gas held under this repurchase agreement. Montana-Dakota and Williston Basin filed suit against Rockwell International Corporation to recover any costs which may be associated with the presence of polychlorinated biphenyls in portions of their natural gas distribution and transmission systems. See Items 1 and 2 under Montana-Dakota and Williston Basin for a discussion of this and other environmental matters. In early 1993, Knife River, together with the Lignite Energy Council, supported the introduction of legislation in North Dakota which would provide severance tax relief for its Gascoyne Mine. Under the legislation, the state will forego its 50 percent share of severance taxes for coal shipped out of state after July 1, 1995, and local political subdivisions are given the option to forego their 35 percent of the tax. The legislation passed both House and Senate with strong support and was signed by the governor. This tax relief will help keep the price of Gascoyne coal competitive. Knife River continues to seek out additional growth opportunities. These include not only identifying possibilities for alternate uses of lignite coal but also investigating the acquisition of other surface mining properties, particularly those relating to sand and gravel aggregates and related products such as ready-mixed concrete, asphalt and various finished aggregate products. In 1993, Knife River acquired two construction materials operations, one in Anchorage, Alaska, and the other with locations in Medford, Oregon and Stockton, California. See Items 1 and 2 under Knife River for a further discussion of these acquisitions. Future cash flows and operating income from oil and natural gas production and reserves are influenced by fluctuations in sales prices as well as the cost of acquiring, finding and producing those reserves. Although Fidelity Oil continues to acquire, develop and explore for oil and natural gas reserves, no assurances can be made as to the future net cash flows from those operations. On January 1, 1993, Montana-Dakota changed its revenue recognition method to include the accrual of estimated unbilled revenues. This change will provide for a better matching of revenues and expenses and is consistent with predominant industry practice. See Note 2 of Notes to Consolidated Financial Statements for a further discussion of this accounting change. The FASB issued SFAS No. 109, "Accounting for Income Taxes" (SFAS No. 109) in February 1992, which changes the accounting method used to measure and recognize income tax effects in financial statements. SFAS No. 109, among other things, requires that existing deferred tax balances be revised to reflect any change in statutory rates. The Company adopted this new standard on January 1, 1993. Based on the provisions of SFAS No. 109, the effect on the Company's financial position or results of operations was not material. Any excess deferred income tax balances associated with rate-regulated activities at the time of implementation have been recorded as a regulatory liability and are expected to be reflected as a reduction in future rates charged customers in accordance with applicable regulatory procedures. See Notes 2 and 13 for a further discussion on the adoption of this standard. In December 1990, the FASB issued SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other than Pensions" (SFAS No. 106). SFAS No. 106 establishes accounting standards for postretirement benefits whereby an employer must recognize in its financial statements on an ongoing basis the actuarially calculated obligation (accumulated postretirement benefit obligation) and related annual costs associated with providing such benefits to employees upon retirement. These benefits are recognized ratably over the employee's term of employment to such employee's eligible retirement date, as earned, rather than the previously used pay-as- you-go practice which recognized such costs when they were paid. The Company adopted this new standard on January 1, 1993. Based on the health care and life insurance benefits which are available to all eligible employees and their dependents upon the employees' retirement, the Company's annual cost based on the provisions of SFAS No. 106 for 1993 is approximately $7.5 million, including amortization of the initial accumulated postretirement benefit obligation of $49 million over 20 years. See Notes 2 and 15 of Notes to Consolidated Financial Statements for a further discussion on the adoption of this standard and the Company's efforts regarding regulatory recovery, including the NDPSC's January 19, 1994, order which requires the expensing, commencing January 1, 1994, of the ongoing SFAS No. 106 incremental expense estimated at $1.0 million annually. The FASB issued SFAS No. 112, "Employers' Accounting for Postemployment Benefits" (SFAS No. 112) in November 1992. SFAS No. 112 establishes accounting standards for postemployment benefits whereby an employer must recognize the benefits provided to former or inactive employees, their beneficiaries, and covered dependents after employment, but before retirement. SFAS No. 112 is effective for fiscal years beginning after December 15, 1993, and therefore, the Company will be required to adopt this new standard in 1994. The Company believes, based on an evaluation of the benefits it provides which are covered by the provisions of SFAS No. 112, that such amounts are not material to its financial position or results of operations. Liquidity and Capital Commitments The Company's construction costs and additional investments in non-regulated mining and construction materials, and oil and natural gas activities (in millions of dollars) for 1991 through 1993 and as anticipated for 1994 through 1996 are summarized in the following table, which also includes the Company's capital needs for the retirement of maturing long-term securities. Estimated 1991 1992 1993 Company/Description 1994 1995 1996 Montana-Dakota: $ 11.7 $ 13.2 $ 16.2 Electric $16.9 $19.8 $ 19.4 5.8 6.5 15.0 Natural Gas Distribution 12.4 10.4 11.3 17.5 19.7 31.2 29.3 30.2 30.7 4.1 9.4 5.4 Williston Basin 19.5 14.6 24.3 .9 16.3 46.5 Knife River 4.5 5.6 7.6 22.3 25.8 24.9 Fidelity 30.0 30.0 30.0 --- --- 1.0 Prairielands .2 .2 --- 44.8 71.2 109.0 83.5 80.6 92.6 Retirement/Repurchase 94.1 140.3 18.4 of Securities 15.3 10.8 10.8 $138.9 $211.5 $127.4 Total $98.8 $91.4 $103.4 In 1993, both Montana-Dakota's and Williston Basin's internal sources provided all of the funds needed for construction purposes. The Company's capital needs to retire maturing long-term corporate securities were $300,000. It is anticipated that Montana-Dakota will continue to provide all of the funds required for its construction requirements for the years 1994 through 1996 from internal sources, through the use of its $30 million revolving credit and term loan agreement, all of which is outstanding at December 31, 1993, 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. Williston Basin expects to meet its construction requirements and financing needs with a combination of internally generated funds, a $35 million line of credit currently available, none of which is outstanding at December 31, 1993, 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. As further described in Items 1 and 2 under Williston Basin, on August 11, 1993, Koch and Williston Basin reached a settlement that terminated the litigation with respect to all parties. The settlement provided that Williston Basin make an immediate cash payment to Koch of $40 million and to transfer to Koch certain natural gas gathering facilities owned by Williston Basin having a cost, net of accumulated depreciation, of approximately $10.4 million. The company believes that it is entitled to recover from ratepayers most of the costs that were incurred as a result of this settlement. Although the amount of the costs which can ultimately be recovered is subject to regulatory and market uncertainties, Williston Basin believes that financing arrangements currently in place are adequate to finance these costs. See Items 1 and 2 under Williston Basin for a further discussion of this settlement and Williston Basin's efforts regarding regulatory recovery. In March and May 1993, Williston Basin was directed by the MMS to pay approximately $3.5 million, plus interest, in claimed royalty underpayments for the period December 1, 1978, through February 29, 1988. In December 1993, Williston Basin also received an assessment from the MDR claiming additional production taxes due of $3.7 million, plus interest, for 1988 through 1991 production. See Items 1 and 2 under Williston Basin for a further discussion of Williston Basin's appeal efforts in these matters. Knife River's 1993 capital needs were met through funds on hand and funds generated from internal sources. It is anticipated that funds on hand and funds generated from internal sources will continue to meet the needs of this business unit for 1994 through 1996, excluding funds which may be required for future acquisitions. Fidelity Oil's 1993 capital needs related to its oil and natural gas acquisition, development and exploration program were met through funds generated from internal sources and a $20 million secured line of credit. It is anticipated that Fidelity's 1994 through 1996 capital needs will be met from internal sources and its secured line of credit. There was $1.5 million outstanding at December 31, 1993, under the secured line of credit. See Note 13 of Notes to the Consolidated Financial Statements for a discussion of deficiency notices received from the IRS proposing substantial additional income taxes. The level of funds which could be required as a result of the proposed deficiencies could be significant if the IRS position were upheld. Prairielands' 1993 capital needs were met through funds generated internally. It is anticipated that Prairielands' 1994 and 1995 capital needs will be met through funds generated from internal sources and a $5 million line of credit, $2.0 million of which is outstanding at December 31, 1993. The Company utilizes its $40 million lines of credit and its $30 million revolving credit and term loan agreement to meet its short-term financing needs and to take advantage of market conditions when timing the placement of long-term or permanent financing. There was $7.5 million outstanding at December 31, 1993, under the lines of credit. 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, 1993, the Company could have issued approximately $153 million of additional first mortgage bonds. The Company's coverage of fixed charges including preferred dividends was 3.0 and 2.4 times for 1993 and 1992, respectively. Additionally, the Company's first mortgage bond interest coverage was 3.4 times in 1993 compared to 3.3 times in 1992. Stockholders' equity as a percent of total capitalization was 56% and 53% at December 31, 1993 and 1992, respectively. Effects of Inflation The Company's consolidated financial statements reflect historical costs, thus combining the impact of dollars spent at various times. Such dollars have been affected by inflation, which generally erodes the purchasing power of monetary assets and increases operating costs. During times of chronic inflation, the loss of purchasing power and increased operating costs could potentially result in inadequate returns to stockholders primarily because of the lag in rate relief granted by regulatory agencies. Further, because the ratemaking process restricts the amount of depreciation expense to historical costs, cash flows from the recovery of such depreciation are inadequate to replace utility plant. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Reference is made to Pages 27 through 51 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 3 through 6 and 13 and 14 of the Company's Proxy Statement dated March 7, 1994 (Proxy Statement) which is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION Reference is made to Pages 7 through 13 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. 1. Financial Statements: Report of Independent Public Accountants. . . . . * Consolidated Statements of Income for each of the three years in the period ended December 31, 1993 . . . . . . . . . . . . . . . * Consolidated Balance Sheets at December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . * Consolidated Statements of Capitalization at December 31, 1993, 1992 and 1991. . . . . . . . * Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1993 . . . . . . . . . . . . . . . * Notes to Consolidated Financial Statements. . . . * 2. Financial Statement Schedules: Report of Independent Public Accountants on Schedules . . . . . . . . . . . . . . . . . ** Schedule V -- Property, Plant and Equipment for the three years ended December 31, 1993 Schedule VI -- Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment for the three years ended December 31, 1993 . . . . . . . . . . . . ** Schedule IX -- Short-Term Borrowings for each of the three years in the period ended December 31, 1993 . . . . . . . . . . . . . . . ** Schedule X -- Supplementary Income Statement Information for each of the three years in the period ended December 31, 1993 . . . . . ** Schedules other than those listed above are omitted because of the absence of the conditions under which they are required, or because the information required is included in the 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 1993 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 1993 is not to be deemed filed as part of this report. **Filed herewith. 3. Exhibits: 3(a) Composite Certificate of Incorporation of MDU Resources Group, Inc., as amended to date, filed as Exhibit 4(a) in Registration No. 33-13092 . . . . . . . . . * 3(b) By-laws of MDU Resources Group, Inc., 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 . . . * + 10(a) Management Incentive Compensation Plan, filed as Exhibit 10(a) in Registration No. 33-66682. . . . . . . . . . . . . . . . * + 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(c) in Registration No. 33-66682. . . . . . . . . . . . . . . . * + 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. . . . . . . . . . . . . . . . * 13 Financial statements and supplementary data as contained in the Annual Report to Stockholders for 1993 . . . . . . . . . . . ** 21 Subsidiaries of MDU Resources Group, Inc. . ** 23(a) Consent of Independent Public Accountants . ** 23(b) Consent of Engineer . . . . . . . . . . . . ** 23(c) Consent of Engineer . . . . . . . . . . . . ** (b) Reports on Form 8-K. None. ____________________ * 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. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES To MDU Resources Group, Inc: We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements included in the MDU Resources Group, Inc. Annual Report to Stockholders incorporated by reference in this Form 10-K, and have issued our report thereon dated January 25, 1994. Our audits of the consolidated financial statements were made for the purpose of forming an opinion on those statements taken as a whole. The schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/ ARTHUR ANDERSEN & CO. ARTHUR ANDERSEN & CO. Minneapolis, Minnesota, January 25, 1994 SCHEDULE V MDU RESOURCES GROUP, INC. PROPERTY, PLANT AND EQUIPMENT For the Year Ended December 31, 1993 (In Thousands)
Column A Column B Column C Column D Column E Column F Other Balance Changes Balance Beginning Additions Add End of Classification of Year at Cost Retirements (Deduct) Year Electric -- Intangible. . . . . . . . . $ 115 $ 27 $ --- $ --- $ 142 Production. . . . . . . . . 225,626 3,010 572 (16) 228,048 Transmission. . . . . . . . 107,048 1,724 269 --- 108,503 Distribution. . . . . . . . 109,518 6,459 814 (76) 115,087 General . . . . . . . . . . 36,983 1,998 680 (1,755) 36,546 Plant Acquisition Adjustments 7,781 --- 414 --- 7,367 Electric Plant Held for Future Use. . . . . . . . 763 --- --- --- 763 Electric Plant Leased to Others --- --- --- 76 76 Construction Work in Progress 4,109 2,978 --- 71 7,158 491,943 16,196 2,749 (1,700)* 503,690 Natural Gas Distribution -- Intangible. . . . . . . . . 235 --- --- --- 235 Distribution. . . . . . . . 101,575 11,979 434 24 113,144 General . . . . . . . . . . 21,969 2,056 953 1,747 24,819 Plant Acquisition Adjustments --- 16 --- --- 16 Construction Work in Progress 1,535 1,422 --- (71) 2,886 125,314 15,473 1,387 1,700* 141,100 Natural Gas Transmission -- Intangible 102 --- --- --- 102 Production and Gathering. . 37,565 1,342 15,443 (64) 23,400 Products Extraction . . . . 1,393 --- 1,390 --- 3 Underground Storage . . . . 17,192 21 --- 4 17,217 Transmission. . . . . . . . 155,149 3,427 6,837 60 151,799 General . . . . . . . . . . 12,933 917 565 --- 13,285 Leased to Others. . . . . . 396 --- 396 --- --- Production Property Held for Future Use. . . . . . . . 107 --- --- --- 107 Natural Gas Stored Underground -- Noncurrent 51,291 --- 2,758 --- 48,533 Plant Acquisition Adjustments 272 --- 11 --- 261 Construction Work in Progress 2,578 1,481 --- --- 4,059 278,978 7,188 27,400 ---* 258,766 Mining and Construction Materials -- Plant Facilities. . . . . . 102,788 44,555 2,345 (99) 144,899 Construction Work in Progress 1,582 (1,467) --- --- 115 104,370 43,088 2,345 (99) 145,014 Oil and Natural Gas Production -- Exploration and Production. 93,667 24,943 1,777 --- 116,833 $1,094,272 $106,888 $35,658 $ (99) $1,165,403
____________________ *Reclassification between plant accounts. Plant is depreciated on a straight-line basis as follows: Electric . . . . . . . . . . . . . . . . . . . .3.2% Natural Gas Distribution. . . . . . . . . . . . .4.3% Natural Gas Transmission. . . . . . . . . . . . .3.5% Mining and Construction Materials . . . . . . . .3.3 to 33.3% Depletion of natural gas, coal and oil production properties is provided on a unit-of-production method based on estimated proved recoverable reserves. SCHEDULE V MDU RESOURCES GROUP, INC. PROPERTY, PLANT AND EQUIPMENT For the Year Ended December 31, 1992 (In Thousands) Column A Column B Column C Column D Column E Column F Other Balance Changes Balance Beginning Additions Add End of Classification of Year at Cost Retirements (Deduct) Year Electric -- Intangible. . . . . . . . . $ 67 $ --- $ --- $ 48 $ 115 Production. . . . . . . . . 224,565 1,258 194 (3) 225,626 Transmission. . . . . . . . 104,744 3,053 748 (1) 107,048 Distribution. . . . . . . . 104,237 6,195 908 (6) 109,518 General . . . . . . . . . . 36,593 1,794 1,066 (338) 36,983 Plant Acquisition Adjustments 8,196 --- 414 (1) 7,781 Electric Plant Held for Future Use. . . . . . . . --- 752 --- 11 763 Construction Work in Progress 3,910 200 --- (1) 4,109 482,312 13,252 3,330 (291)* 491,943 Natural Gas Distribution -- Intangible. . . . . . . . . 235 --- --- --- 235 Distribution. . . . . . . . 97,496 4,690 611 --- 101,575 General . . . . . . . . . . 21,235 1,437 993 290 21,969 Construction Work in Progress 1,189 345 --- 1 1,535 120,155 6,472 1,604 291* 125,314 Natural Gas Transmission -- Intangible. . . . . . . . . 102 --- --- --- 102 Production and Gathering. . 37,846 254 570 35 37,565 Products Extraction . . . . 1,393 --- --- --- 1,393 Underground Storage . . . . 17,103 141 52 --- 17,192 Transmission. . . . . . . . 148,049 7,713 580 (33) 155,149 General . . . . . . . . . . 12,577 1,145 787 (2) 12,933 Leased to Others. . . . . . 396 --- --- --- 396 Production Property Held for Future Use. . . . . . . . 107 --- --- --- 107 Natural Gas Stored Underground -- Noncurrent 52,835 --- 1,544 --- 51,291 Plant Acquisition Adjustments 282 --- 10 --- 272 Construction Work in Progress 879 1,699 --- --- 2,578 271,569 10,952 3,543 ---* 278,978 Mining and Construction Materials -- Plant Facilities. . . . . . 88,535 14,713 460 --- 102,788 Construction Work in Progress --- 1,582 --- --- 1,582 88,535 16,295 460 --- 104,370 Oil and Natural Gas Production -- Exploration and Production. 68,253 25,778 364 --- 93,667 $1,030,824 $72,749 $9,301 $ --- $1,094,272
____________________ *Reclassification between plant accounts. Plant is depreciated on a straight-line basis as follows: Electric . . . . . . . . . . . . . . . . . . . .3.2% Natural Gas Distribution. . . . . . . . . . . . .4.3% Natural Gas Transmission. . . . . . . . . . . . .3.1% Mining and Construction Materials . . . . . . . .3.3 to 33.3% Depletion of natural gas, coal and oil production properties is provided on a unit-of-production method based on estimated proved recoverable reserves. SCHEDULE V MDU RESOURCES GROUP, INC. PROPERTY, PLANT AND EQUIPMENT For the Year Ended December 31, 1991 (In Thousands)
Column A Column B Column C Column D Column E Column F Other Balance Changes Balance Beginning Additions Add End of Classification of Year at Cost Retirements (Deduct) Year Electric -- Intangible. . . . . . . . . $ 66 $ --- $ --- $ 1 $ 67 Production. . . . . . . . . 219,371 7,712 2,518 --- 224,565 Transmission. . . . . . . . 103,765 1,317 296 (42) 104,744 Distribution. . . . . . . . 101,712 3,435 959 49 104,237 General . . . . . . . . . . 34,588 2,218 739 526 36,593 Plant Acquisition Adjustments 8,610 --- 414 --- 8,196 Construction Work in Progress 6,595 (2,689) --- 4 3,910 474,707 11,993 4,926 538* 482,312 Natural Gas Distribution -- Intangible. . . . . . . . . 236 --- --- (1) 235 Distribution. . . . . . . . 94,363 3,645 512 --- 97,496 General . . . . . . . . . . 21,015 1,621 867 (534) 21,235 Construction Work in Progress 684 508 --- (3) 1,189 116,298 5,774 1,379 (538)* 120,155 Natural Gas Transmission -- Intangible. . . . . . . . . 102 --- --- --- 102 Production and Gathering. . 38,688 144 973 (13) 37,846 Products Extraction . . . . 1,392 1 --- --- 1,393 Underground Storage . . . . 16,786 321 5 1 17,103 Transmission. . . . . . . . 146,034 2,453 445 7 148,049 General . . . . . . . . . . 11,660 1,396 484 5 12,577 Leased to Others. . . . . . 396 --- --- --- 396 Production Property Held for Future Use. . . . . . . . 107 --- --- --- 107 Natural Gas Stored Underground -- Noncurrent 51,797 1,038 --- --- 52,835 Plant Acquisition Adjustments 293 --- 11 --- 282 Construction Work in Progress 1,101 (222) --- --- 879 268,356 5,131 1,918 ---* 271,569 Mining and Construction Materials -- Plant Facilities. . . . . . 88,477 939 881 --- 88,535 Construction Work in Progress 30 (30) --- --- --- 88,507 909 881 --- 88,535 Oil and Natural Gas Production -- Exploration and Production. 46,290 22,284 321 --- 68,253 $994,158 $46,091 $9,425 $ --- $1,030,824
____________________ *Reclassification between plant accounts. Plant is depreciated on a straight-line basis as follows: Electric . . . . . . . . . . . . . . . . . . . .3.3% Natural Gas Distribution. . . . . . . . . . . . .4.3% Natural Gas Transmission. . . . . . . . . . . . .3.0% Mining and Construction Materials . . . . . . . .3.3 to 33.3% Depletion of natural gas, coal and oil production properties is provided on a unit-of-production method based on estimated proved recoverable reserves. SCHEDULE VI MDU RESOURCES GROUP, INC. ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION of Property, Plant and Equipment For the Year Ended December 31, 1993 (In Thousands)
Column A Column B Column C Column D Column E Column F Additions Other Balance Charged to Changes Balance Beginning Cost and Add End of Description of Year Expenses(a) Retirements (Deduct) Year Accumulated Provision for Depreciation: Electric -- Intangible . . . . . . . $ 61 $ 27 $ --- $ --- $ 88 Production . . . . . . . . 100,559 6,686 575 (16) 106,654 Transmission . . . . . . . 45,042 2,532 158 1 47,417 Distribution . . . . . . . 49,131 3,693 1,009 1 51,816 General. . . . . . . . . . 17,389 1,751 562 (27) 18,551 Retirement Work in Progress 3,105 --- 78 --- 3,027 215,287 14,689 2,382 (41) 227,553 Natural Gas Distribution -- Intangible . . . . . . . . 102 27 --- --- 129 Distribution . . . . . . . 53,830 4,535 648 426 58,143 General. . . . . . . . . . 10,243 995 499 61 10,800 Retirement Work in Progress (18) --- 14 --- (32) 64,157 5,557 1,161 487 69,040 Natural Gas Transmission -- Production and Gathering . 6,836 1,293 3,056 642 5,715 Products Extraction. . . . 757 38 795 --- --- Underground Storage. . . . 5,791 397 (1) 2 6,191 Transmission . . . . . . . 77,750 4,539 3,786 8 78,511 General. . . . . . . . . . 6,630 1,014 325 1 7,320 Leased to Others . . . . . 179 4 183 --- --- Retirement Work in Progress 113 128 195 (1) 45 98,056 7,413 8,339 652 97,782 Mining and Construction Materials. . . . . . . . . 66,206 5,455 2,299 49 69,411 $443,706 $33,114 $14,181 $1,147 $463,786 Accumulated Provision for Depletion: Natural Gas Transmission -- Production . . . . . . . . $ 1,078 $ 18 $ --- $ --- $ 1,096 Mining and Construction Materials. . . . . . . . . 260 237 --- (148) 349 Oil and Natural Gas Production 24,188 12,034 2 --- 36,220 $ 25,526 $12,289 $ 2 $ (148) $ 37,665
____________________ (a) Includes depreciation on transportation and other equipment that is charged to construction, operations, maintenance and merchandising accounts. SCHEDULE VI MDU RESOURCES GROUP, INC. ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION of Property, Plant and Equipment For the Year Ended December 31, 1992 (In Thousands)
Column A Column B Column C Column D Column E Column F Additions Other Balance Charged to Changes Balance Beginning Cost and Add End of Description of Year Expenses(a) Retirements (Deduct) Year Accumulated Provision for Depreciation: Electric -- Intangible . . . . . . . . $ 38 $ 23 $ --- $ --- $ 61 Production . . . . . . . . 94,106 6,703 251 1 100,559 Transmission . . . . . . . 43,267 2,475 702 2 45,042 Distribution . . . . . . . 46,660 3,505 1,032 (2) 49,131 General. . . . . . . . . . 16,705 1,773 998 (91) 17,389 Retirement Work in Progress 2,958 --- (147) --- 3,105 203,734 14,479 2,836 (90) 215,287 Natural Gas Distribution -- Intangible . . . . . . . . 75 27 --- --- 102 Distribution . . . . . . . 50,453 4,271 894 --- 53,830 General. . . . . . . . . . 10,051 839 737 90 10,243 Retirement Work in Progress (40) --- (22) --- (18) 60,539 5,137 1,609 90 64,157 Natural Gas Transmission -- Production and Gathering . 6,464 974 449 (153) 6,836 Products Extraction. . . . 665 92 --- --- 757 Underground Storage. . . . 5,501 360 70 --- 5,791 Transmission . . . . . . . 74,008 4,152 564 154 77,750 General. . . . . . . . . . 6,316 983 668 (1) 6,630 Leased to Others . . . . . 168 11 --- --- 179 Retirement Work in Progress 1 118 6 --- 113 93,123 6,690 1,757 --- 98,056 Mining and Construction Materials. . . . . . . . . 62,157 4,474 440 15 66,206 $419,553 $30,780 $6,642 $ 15 $443,706 Accumulated Provision for Depletion: Natural Gas Transmission -- Production . . . . . . . . $ 1,062 $ 16 $ --- $ --- $ 1,078 Mining and Construction Materials. . . . . . . . . 215 53 8 --- 260 Oil and Natural Gas Production 15,447 8,817 76 --- 24,188 $ 16,724 $ 8,886 $ 84 $ --- $ 25,526
____________________ (a) Includes depreciation on transportation and other equipment that is charged to construction, operations, maintenance and merchandising accounts. SCHEDULE VI MDU RESOURCES GROUP, INC. ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION of Property, Plant and Equipment For the Year Ended December 31, 1991 (In Thousands)
Column A Column B Column C Column D Column E Column F Additions Other Balance Charged to Changes Balance Beginning Cost and Add End of Description of Year Expenses(a) Retirements (Deduct) Year Accumulated Provision for Depreciation: Electric -- Intangible . . . . . . . . $ 24 $ 13 $ --- $ 1 $ 38 Production . . . . . . . . 89,911 6,767 2,572 --- 94,106 Transmission . . . . . . . 41,167 2,448 328 (20) 43,267 Distribution . . . . . . . 44,331 3,388 1,079 20 46,660 General. . . . . . . . . . 15,462 1,687 672 228 16,705 Retirement Work in Progress 2,952 --- (6) --- 2,958 193,847 14,303 4,645 229 203,734 Natural Gas Distribution -- Intangible . . . . . . . . 48 27 --- --- 75 Distribution . . . . . . . 47,069 4,112 728 --- 50,453 General. . . . . . . . . . 9,859 822 400 (230) 10,051 Retirement Work in Progress (58) --- (18) --- (40) 56,918 4,961 1,110 (230) 60,539 Natural Gas Transmission -- Production and Gathering . 6,436 890 862 --- 6,464 Products Extraction. . . . 572 93 --- --- 665 Underground Storage. . . . 5,161 346 6 --- 5,501 Transmission . . . . . . . 70,226 4,031 249 --- 74,008 General. . . . . . . . . . 5,753 883 320 --- 6,316 Leased to Others . . . . . 158 10 --- --- 168 Retirement Work in Progress (41) 123 81 --- 1 88,265 6,376 1,518 --- 93,123 Mining and Construction Materials. . . . . . . . . 59,028 4,006 877 --- 62,157 $398,058 $29,646 $8,150 $ (1) $419,553 Accumulated Provision for Depletion: Natural Gas Transmission -- Production . . . . . . . . $ 1,049 $ 13 $ --- $ --- $ 1,062 Mining and Construction Materials. . . . . . . . . 186 29 --- --- 215 Oil and Natural Gas Production 9,460 6,061 74 --- 15,447 $ 10,695 $ 6,103 $ 74 $ --- $ 16,724
____________________ (a) Includes depreciation on transportation and other equipment that is charged to construction, operations, maintenance and merchandising accounts. SCHEDULE IX MDU RESOURCES GROUP, INC. SHORT-TERM BORROWINGS For the Years Ended December 31, 1993, 1992 and 1991 (Dollars In Thousands)
Column A Column B Column C Column D Column E Column F Highest Month Average Weighted Weighted End Balance Daily Average Balance Average Outstanding Balance Interest Rate Category of End of Interest During the Outstanding During the Short-Term Borrowings Year Rate Year During Year Year Notes Payable to Banks: 1993 . . . . . . . . $ --- ---% $ --- $ --- ---% 1992 . . . . . . . . $ --- ---% $ --- $ --- ---% 1991 . . . . . . . . $ --- ---% $ --- $ --- ---% Commercial Paper: 1993 . . . . . . . . $ 9,540 4.2% $33,190 $17,285 3.6% 1992 . . . . . . . . $ 7,775 5.2% $37,875 $22,735 4.0% 1991 . . . . . . . . $ 170 6.5% $24,000 $ 8,788 6.5%
The Company and its subsidiaries had unsecured lines of credit from several banks totalling $86 million at December 31, 1993, $80 million at December 31, 1992, and $73 million at December 31, 1991. 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. The unused portions of the lines of credit are subject to withdrawal based on the occurrence of certain events. The weighted average interest rate is calculated by dividing interest expense for the year by the amount of average daily borrowings outstanding. SCHEDULE X MDU RESOURCES GROUP, INC. SUPPLEMENTARY INCOME STATEMENT INFORMATION For the Years Ended December 31, 1993, 1992 and 1991 (In Thousands)
Column A Column B Item Charged to Costs and Expenses 1993 1992 1991 Maintenance and Repairs. . . . . . . . . $21,462 $17,767 $18,334 Taxes, Other Than Income -- Real Estate and Personal Property . . $ 9,598 $ 8,786 $ 8,431 State Severance . . . . . . . . . . . 5,105 5,555 5,968 Other . . . . . . . . . . . . . . . . 8,862 8,458 8,243 $23,565 $22,799 $22,642
Note: Depreciation and amortization of intangible assets, preoperating costs and similar deferrals, royalties and advertising costs are omitted as they are each less than 1% of operating revenues. EX-3.B 2 BYLAWS FOR 10-K, EXHIBIT 3.B Bylaws of MDU RESOURCES GROUP, INC. Rev. 11/93 TABLE OF CONTENTS TO BYLAWS 1. Amendments 2. Certificates of Stock 3. Chairman of the Board 4. Checks 5. Committees 6. Compensation of Directors 7. Directors 8. Directors Indemnified 9. Directors Meetings 10. Dividends 11. Election of Officers 12. Execution of Instruments 13. Execution of Proxies 14. Fiscal Year 15. Inspection of Books 16. Lost Certificate 17. Notices 18. Officers 19. Offices 20. President 21. Qualifications 22. Record Date 23. Registered Stockholders 24. Seal 25. Secretary 26. Stockholders Meetings 27. Transfer of Stock 28. Treasurer 29. Vice President 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. 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 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, 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. 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 be a Chairman of the Board, a President, 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 Chairman of the Board. The Chairman of the Board shall preside at all meetings of the stockholders and Directors and, subject to the Board of Directors, shall determine the general policies of the Corporation. 5.06 The President. The President shall preside at all meetings of the stockholders and the Board of Directors in the absence of the Chairman of the Board, 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 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. 5.08 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 President, 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. 5.09 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. 5.10 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. 5.11 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 Chairman, President 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. 5.12 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 Chairman or President of this Corporation, or, in the absence of either 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 Chairman, President 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 Chairman or President and Secretary shall seem 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 the Chairman, President nor any Vice President of this Corporation 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 in the name of the Corporation by, the Chairman or Vice Chairman of the Board of Directors, or the President or a Vice President and by the Treasurer or an Assistant Treasurer, or the Secretary or an Assistant Secretary of the Corporation, certifying the number of shares owned by him in the Corporation. 6.02 Signatures. Any of or all the signatures on the certificates may be facsimile. In case any officer, transfer agent or registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, transfer agent or registrar before such certificate is issued, it may be issued by the Corporation with the same effect as if he were such officer, transfer agent or registrar at the date of issue. 6.03 Special Designation on Certificates. If the Corporation shall be authorized to issue more than one class of stock or more than one series of any class, the powers, designations, preferences and relative, participating, optional or other special rights of each class of stock or series thereof and the qualifications, limitations, or restrictions of such preferences and/or rights shall be set forth in full or summarized on the face or back of the certificate which the Corporation shall issue to represent such class or series of stock, provided, that, except as otherwise provided in Section 202 of the General Corporation Law of Delaware in lieu of the foregoing requirements, there may be set forth on the face or back of the certificate which the Corporation shall issue to represent such class or series of stock, a statement that the Corporation will furnish, without charge to each stockholder who so requests, the powers, designations, preferences and relative, participating, optional or other special rights of each class of stock or series thereof and the qualifications, limitations or restrictions of such preferences and/or rights. 6.04 Lost Certificates. The Board of Directors may direct a new certificate or certificates to be issued in place of any certificate or certificates theretofore issued by the Corporation alleged to have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the person claiming the certificate of stock to be lost, stolen or destroyed. When authorizing such issue of a new certificate or certificates, the Board of Directors may, in its discretion and as a condition precedent to the issuance thereof, require the owner of such lost, stolen or destroyed certificate or certificates, or his legal representative, to advertise the same in such manner as it shall require and/or to give the Corporation a bond in such sum as it may direct as indemnity against any claim that may be made against the Corporation with respect to the certificate alleged to have been lost, stolen or destroyed. 6.05 Transfers of Stock. Upon surrender to the Corporation or the transfer agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignation or authority to transfer, it shall be the duty of the Corporation to issue a new certificate to the person entitled thereto, cancel the old certificate and record the transaction upon its books. 6.06 Record Date. In order that the Corporation may determine the stockholders entitled to notice of or to vote at any meeting of stockholders or any adjournment thereof, or to express consent to corporate action in writing without a meeting, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action, the Board of Directors may fix, in advance, a record date, which shall not be more than sixty days nor less than ten days before the date of such meeting, nor more than sixty days prior to any other action. A determination of stockholders of record entitled to notice of or to vote at a meeting of stockholders shall apply to any adjournment of the meeting; provided, however, that the Board of Directors may fix a new record date for the adjourned meeting. 6.07 Registered Stockholders. The Corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends, and to vote as such owner, and to hold liable for calls and assessments a person registered on its books as the owner of shares, and shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of Delaware. GENERAL PROVISIONS 7.01 Dividends. Dividends upon the capital stock of the Corporation, subject to the provisions of the Certificates of Incorporation, if any, may be declared by the Board of Directors at any regular or special meeting, pursuant to law. Dividends may be paid in cash, in property, or in shares of the capital stock, subject to the provisions of the Certificates of Incorporation. Before payment of any dividend, there may be set aside out of the funds of the Corporation available for dividends such sum or sums as the Directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meeting contingencies, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for such other purpose as the Directors shall think conducive to the interest of the Corporation, and the Directors may modify or abolish any such reserve in the manner in which it was created. 7.02 Checks. All checks or demands for money and notes of the Corporation shall be signed by such officer or officers or such other person or persons as the Board of Directors may from time to time designate or as designated by an officer of the company if so authorized by the Board of Directors. 7.03 Fiscal year. The fiscal year of the Corporation shall be the calendar year. 7.04 Seal. The corporate seal shall have inscribed thereon the name of the Corporation, the year of its organization and the words "Corporate Seal, Delaware." The seal may be used by causing it or a facsimile thereof to be impressed or affixed or imprinted, or otherwise. 7.05 Inspection of Books and Records. Any stockholder of record, in person or by attorney or other agent, shall, upon written demand under oath stating the purpose thereof, have the right, during the usual hours of business, to inspect for any proper purpose the Corporation s stock ledger, a list of its stockholders, and its other books and records, and to make copies or extracts therefrom. A proper purpose shall mean a purpose reasonably related to such person s interest as a stockholder. In every instance where an attorney or other agent shall be the person who seeks the right to inspection, the demand under oath shall be accompanied by a power of attorney or such other writing which authorizes the attorney or other agent to so act on behalf of the stockholder. The demand under oath shall be directed to the Corporation at its registered office in the State of Delaware or at its principal place of business in Bismarck, North Dakota. 7.06 Amendments. These Bylaws may be altered, amended or repealed or new Bylaws may be adopted by the stockholders or by the Board of Directors, when such power is conferred upon the Board of Directors by the Certificate of Incorporation, at any regular meeting of the stockholders or of the Board of Directors or at any special meeting of the stockholders or of the Board of Directors if notice of such alteration, amendment, repeal or adoption of new Bylaws be contained in the notice of such special meeting. 7.07 Indemnification of Officers, Directors, Employees and Agents; Insurance. (a) The Corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the Corporation) by reason of the fact that he is or was a director, officer, employee or agent of the Corporation, or is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the Corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction, or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the person did not act in good faith and in a manner which he reasonably believed to be in or not opposed to the best interest of the Corporation, and, with respect to any criminal action or proceeding, had reasonable cause to believe that his conduct was unlawful. (b) The Corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the Corporation to procure a judgment in its favor by reason of the fact that he is or was a director, officer, employee or agent of the Corporation, or is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against expenses (including attorneys fees) actually and reasonably incurred by him in connection with the defense or settlement of such action or suit if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the Corporation and except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the Corporation, unless and only to the extent that the Court of Chancery or the court in which such action or suit was brought, shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Court of Chancery or such other court shall deem proper. (c) To the extent that a director, officer, employee or agent of a corporation has been successful on the merits or otherwise in defense of any action, suit or proceeding referred to in subsections (a) and (b), or in defense of any claim, issue or matter therein, he shall be indemnified against expenses (including attorneys fees) actually and reasonably incurred by him in connection therewith. (d) Any indemnification under the foregoing provisions of this Section (unless ordered by a court) shall be made by the Corporation only as authorized in the specific case upon a determination that indemnification of the director, officer, employee or agent is proper in the circumstances because he has met the applicable standard of conduct as set forth in subsections (a) and (b) of this Section. Such determination shall be made (i) by the Board of Directors by a majority vote of a quorum consisting of directors who were not parties to such action, suit or proceeding, or (ii) if such a quorum is not obtainable, or, even if obtainable, a quorum of disinterested directors so directs, by independent legal counsel in a written opinion, or (iii) by the stockholders. (e) Expenses (including attorneys fees) incurred by an officer or director in defending any civil, criminal, administrative or investigative action, suit or proceeding shall be paid by the Corporation in advance of the final disposition of such action, suit or proceeding upon receipt of an undertaking by or on behalf of the director or officer to repay such amount if it shall ultimately be determined that he is not entitled to be indemnified by the Corporation as authorized in this Section. Once the Corporation has received the undertaking, the Corporation shall pay the officer or director within 30 days of receipt by the Corporation of a written application from the officer or director for the expenses incurred by that officer or director. In the event the Corporation fails to pay within the 30-day period, the applicant shall have the right to sue for recovery of the expenses contained in the written application and, in addition, shall recover all attorneys fees and expenses incurred in the action to enforce the application and the rights granted in this Section 7.07. Expenses (including attorneys fees) incurred by other employees and agents shall be paid upon such terms and conditions, if any, as the Board of Directors deems appropriate. (f) The indemnification and advancement of expenses provided by, or granted pursuant to, the other subsections of this Section shall not be deemed exclusive of any other rights to which those seeking indemnity or advancement of expenses may be entitled under any bylaw, agreement, vote of stockholders or disinterested directors or otherwise, both as to action in his official capacity and as to action in another capacity while holding such office. (g) The Corporation may purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the Corporation, or is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against any liability asserted against him and incurred by him in any such capacity, or arising out of his status as such, whether or not the Corporation would have the power to indemnify him against such liability under the provisions of this Section. (h) For the purposes of this Section, references to "the Corporation" include all constituent corporations absorbed in a consolidation or merger, as well as the resulting or surviving corporation, so that any person who is or was a director, officer, employee or agent of such a constituent corporation or is or was serving at the request of such constituent corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, shall stand in the same position under the provisions of this Section with respect to the resulting or surviving corporation as he would if he had served the resulting or surviving corporation in the same capacity. (i) For purposes of this Section, references to "other enterprises" shall include employee benefit plans; references to "fines" shall include any excise taxes assessed on a person with respect to any employee benefit plan; and references to "serving at the request of the Corporation" shall include any service as a director, officer, employee or agent of the Corporation which imposes duties on, or involves services by, such director, officer, employee or agent with respect to an employee benefit plan, its participants or beneficiaries; and a person who acted in good faith and in a manner he reasonably believed to be in the interest of the participants and beneficiaries of an employee benefit plan shall be deemed to have acted in a manner "not opposed to the best interests of the Corporation" as referred to in this Section. (j) The indemnification and advancement of expenses provided by, or granted pursuant to, this Section shall, unless otherwise provided when authorized or ratified, continue as to a person who has ceased to be a director, officer, employee or agent and shall inure to the benefit of the heirs, executors and administrators of such a person. EX-13 3 FOOTNOTES FROM ANNUAL REPORT FOR 10-K, EX-13 [TEXT] MDU RESOURCES GROUP, INC. 1993 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 its regulated and non-regulated businesses and necessarily include some amounts that are based on informed judgments and estimates of management. To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls designed to provide assurance, on a cost effective basis, that transactions are carried out in accordance with management's authorizations and that assets are safeguarded against loss from unauthorized use or disposition. The system includes an organizational structure which provides an appropriate segregation of responsibilities, careful selection and training of personnel, written policies and procedures and periodic reviews by the internal audit department. In addition, the company has a policy which requires all employees to acknowledge their responsibility to maintain a high standard of 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 & Co., 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 & Co. have full and free access to the audit committee, without management present, to discuss auditing, internal accounting control and financial reporting matters. Arthur Andersen & Co. 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, 1993 1992 1991 (In thousands, except per share amounts) Operating revenues: Electric . . . . . . . . . . . . . . $131,109 $123,908 $128,708 Natural gas. . . . . . . . . . . . . 178,981 159,438 173,865 Mining and construction materials. . 90,397 45,032 41,201 Oil and natural gas production . . . 39,125 33,797 33,939 439,612 362,175 377,713 Operating expenses: Fuel and purchased power . . . . . . 41,298 37,892 38,379 Purchased natural gas sold . . . . . 78,121 58,420 66,559 Operation and maintenance. . . . . . 167,374 126,311 128,253 Depreciation, depletion and amortization . . . . . . . . . . . 45,162 39,694 36,577 Taxes, other than income . . . . . . 23,565 22,799 22,642 355,520 285,116 292,410 Operating income: Electric . . . . . . . . . . . . . . 30,520 30,188 34,647 Natural gas distribution . . . . . . 4,730 4,509 8,518 Natural gas transmission . . . . . . 20,108 21,331 19,904 Mining and construction materials. . 16,984 11,532 9,682 Oil and natural gas production . . . 11,750 9,499 12,552 84,092 77,059 85,303 Other income -- net . . . . . . . . . 3,877 273 5,957 Interest expense -- net . . . . . . . 25,273 25,227 27,952 Carrying costs on natural gas repurchase commitment (Note 5) . . . 3,897 5,834 8,483 Income before taxes. . . . . . . . . . 58,799 46,271 54,825 Income taxes . . . . . . . . . . . . . 19,982 10,900 16,808 Income before cumulative effect of accounting change . . . . . . . . 38,817 35,371 38,017 Cumulative effect of accounting change (Note 2). . . . . . . . . . . 5,521 --- --- Net income . . . . . . . . . . . . . . 44,338 35,371 38,017 Dividends on preferred stocks. . . . . 802 807 812 Earnings on common stock . . . . . . . $ 43,536 $ 34,564 $ 37,205 Earnings per common share: Earnings before cumulative effect of accounting change. . . . . . . . $ 2.00 $ 1.82 $ 1.96 Cumulative effect of accounting change. . . . . . . . . . . . . . . .29 --- --- Earnings . . . . . . . . . . . . . . $ 2.29 $ 1.82 $ 1.96 Dividends per common share . . . . . . $ 1.52 $ 1.46 $ 1.435 Average common shares outstanding . . 18,985 18,985 18,985 Pro forma amounts assuming retroactive application of accounting change: Net income . . . . . . . . . . . . . $ 38,817 $ 35,852 $ 37,619 Earnings per common share. . . . . . $ 2.00 $ 1.85 $ 1.94 The accompanying notes are an integral part of these consolidated statements. /TABLE CONSOLIDATED BALANCE SHEETS MDU RESOURCES GROUP, INC.
December 31, 1993 1992 1991 (In thousands) ASSETS Property, plant and equipment: Electric . . . . . . . . . . . . . $ 503,690 $ 491,943 $ 482,312 Natural gas distribution . . . . . 141,100 125,314 120,155 Natural gas transmission . . . . . 258,766 278,978 271,569 Mining and construction materials. 145,014 104,370 88,535 Oil and natural gas production . . 116,833 93,667 68,253 1,165,403 1,094,272 1,030,824 Less accumulated depreciation, depletion and amortization . . . 501,451 469,232 436,277 663,952 625,040 594,547 Current assets: Cash and cash equivalents. . . . . 71,699 66,838 54,593 Receivables. . . . . . . . . . . . 67,553 57,902 43,334 Inventories. . . . . . . . . . . . 19,415 18,214 16,228 Exchange natural gas receivable. . 727 25,195 25,992 Deferred income taxes. . . . . . . 32,243 18,962 11,335 Other prepayments and current assets . . . . . . . . . 13,535 15,302 10,913 205,172 202,413 162,395 Natural gas available under repurchase commitment (Note 5) . . 79,031 92,038 99,449 Investments. . . . . . . . . . . . . 16,858 61,934 67,188 Deferred charges and other assets. . 76,038 43,085 41,112 $1,041,051 $1,024,510 $ 964,691 CAPITALIZATION AND LIABILITIES Capitalization (see separate statements): Common stockholders' investment. . $ 318,131 $ 303,452 $ 296,605 Preferred stocks . . . . . . . . . 17,100 17,200 17,300 Long-term debt . . . . . . . . . . 231,770 249,845 220,623 567,001 570,497 534,528 Commitments and contingencies (Notes 3, 4, 5, 6, 15 and 18). . . --- --- --- Current liabilities: Short-term borrowings. . . . . . . 9,540 7,775 --- Accounts payable . . . . . . . . . 24,967 25,397 18,495 Taxes payable. . . . . . . . . . . 9,204 8,958 10,120 Other accrued liabilities, including reserved revenues. . . 105,195 87,950 69,340 Exchange natural gas deliverable . 2,371 25,046 26,641 Dividends payable. . . . . . . . . 7,605 7,226 7,037 Long-term debt and preferred stock due within one year. . . . 15,300 300 2,400 174,182 162,652 134,033 Natural gas repurchase commitment (Note 5) . . . . . . . . . . . . . 98,525 114,937 123,981 Deferred credits: Deferred income taxes and unamortized investment tax credit . . . . . . . . . . . . . 124,978 135,571 138,758 Other. . . . . . . . . . . . . . . 76,365 40,853 33,391 201,343 176,424 172,149 $1,041,051 $1,024,510 $ 964,691 The accompanying notes are an integral part of these consolidated statements. /TABLE CONSOLIDATED STATEMENTS OF CAPITALIZATION MDU RESOURCES GROUP, INC.
December 31, 1993 1992 1991 (In thousands) Common stockholders' investment: Common stock (Note 9): Authorized -- 50,000,000 shares, $5 par value in 1993, 1992 and 1991 Outstanding -- 18,984,654 shares . $ 94,923 $ 94,923 $ 94,923 Other paid in capital . . . . . . . . 64,210 64,210 64,210 Retained earnings (Note 10) . . . . . 158,998 144,319 137,472 Total common stockholders' investment. . . . . . . . . . . . . 318,131 303,452 296,605 Preferred stocks (Note 11): Authorized: Preferred -- 500,000 shares, cumulative, par value $100, issuable in series Preferred stock A -- 1,000,000 shares, cumulative, without par value, issuable in series (none outstanding) Preference -- 500,000 shares, cumulative, without par value, issuable in series (none outstanding) Outstanding: Subject to mandatory redemption requirements -- Preferred -- 5.10% Series -- 22,000 shares in 1993 (23,000 in 1992 and 24,000 in 1991). . . . . . . . 2,200 2,300 2,400 Other preferred stock -- 4.50% Series -- 100,000 shares. . . . . . . . . . . . 10,000 10,000 10,000 4.70% Series -- 50,000 shares. . . . . . . . . . . . 5,000 5,000 5,000 15,000 15,000 15,000 Total preferred stocks 17,200 17,300 17,400 Less current maturities and sinking fund requirements. . . . . . 100 100 100 Net preferred stocks . . . . . . . . . 17,100 17,200 17,300 Long-term debt (Note 12): First mortgage bonds and notes . . . . 195,850 195,850 180,400 Pollution control lease and note obligation, 6.2%, due in annual installments to 2004 . . . . . 4,800 5,000 26,050 Senior secured note, 8.43%, due December 31, 2000 . . . . . . . . 15,000 --- --- Secured line of credit at various interest rates, terminating October 6, 2002 . . . . . . . . . . . 1,500 19,400 --- Term loan at various interest rates, terminating December 31, 1996. . . . 30,000 30,000 16,900 Other. . . . . . . . . . . . . . . . . (180) (205) (427) Total long-term debt . . . . . . . . . 246,970 250,045 222,923 Less current maturities and sinking fund requirements. . . . . . . . . . 15,200 200 2,300 Net long-term debt . . . . . . . . . . 231,770 249,845 220,623 Total capitalization . . . . . . . . . .$567,001 $570,497 $534,528 The accompanying notes are an integral part of these consolidated statements. /TABLE CONSOLIDATED STATEMENTS OF CASH FLOWS MDU RESOURCES GROUP, INC.
Years ended December 31, 1993 1992 1991 (In thousands) Operating activities: Net income . . . . . . . . . . . . . $ 44,338 $ 35,371 $ 38,017 Cumulative effect of accounting change . . . . . . . . . . . . . . (5,521) --- --- Adjustments to reconcile net income to net cash provided by operations: Depreciation, depletion and amortization . . . . . . . . . . 45,162 39,694 36,577 Deferred income taxes and investment tax credit -- net . . 16,040 (789) 747 Recovery of deferred natural gas contract litigation settlement costs, net of income taxes . . . 8,467 3,996 4,633 Changes in current assets and liabilities -- Receivables. . . . . . . . . . . (775) (14,568) 983 Inventories. . . . . . . . . . . (1,201) (1,834) 5,457 Other current assets . . . . . . 12,954 (11,219) 4,402 Accounts payable . . . . . . . . (430) 6,902 (1,420) Other current liabilities. . . . (8,160) 16,042 4,530 Other noncurrent changes . . . . . (13,687) 190 1,298 Net cash provided by operations. . . 97,187 73,785 95,224 Financing activities: Net change in short-term borrowings. 1,765 7,775 --- Issuance of long-term debt . . . . . 15,200 167,100 84,920 Repayment of long-term debt. . . . . (18,300) (140,200) (93,611) Retirement of preferred stocks . . . (100) (100) (504) Retirement of natural gas repurchase commitment. . . . . . . (16,412) (9,044) --- Dividends paid . . . . . . . . . . . (29,659) (28,524) (28,055) Net cash used in financing activities . . . . . . . . . . . . (47,506) (2,993) (37,250) Investing activities: Additions to property, plant and equipment and acquisitions of businesses -- Electric . . . . . . . . . . . . . (16,156) (13,226) (11,728) Natural gas distribution . . . . . (15,012) (6,461) (5,758) Natural gas transmission . . . . . (3,669) (9,452) (4,093) Mining and construction materials. (43,123) (16,295) (909) Oil and natural gas production . . (24,943) (25,778) (22,284) (102,903) (71,212) (44,772) Sale of natural gas available under repurchase commitment. . . . 13,007 7,411 --- Investments. . . . . . . . . . . . . 45,076 5,254 (2,851) Net cash used in investment activities . . . . . . . . . . . . (44,820) (58,547) (47,623) Increase in cash and cash equivalents. . . . . . . . . . . . 4,861 12,245 10,351 Cash and cash equivalents -- beginning of year. . . . . . . . . 66,838 54,593 44,242 Cash and cash equivalents -- end of year. . . . . . . . . . . . $ 71,699 $ 66,838 $ 54,593 The accompanying notes are an integral part of these consolidated statements. /TABLE [TEXT] NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MDU RESOURCES GROUP, INC. Years Ended December 31, 1993, 1992 and 1991 NOTE 1 Statement of Principal Accounting Policies Basis of presentation The consolidated financial statements of MDU Resources Group, Inc. (the "company") include the accounts of two regulated businesses -- retail sales of electricity, natural gas and propane, and natural gas transmission, storage and sales at wholesale -- and two non-regulated businesses -- mining and construction materials 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 its non-regulated businesses. 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. Property, plant and equipment and investments Additions to property, plant and equipment are recorded at cost when first placed in service. When utility 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. The company is permitted to capitalize an allowance for funds used during construction (AFUDC) on utility construction projects and to include such amounts in rate base when the related facilities are placed in service. AFUDC capitalized was insignificant in 1993, 1992 and 1991. Property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets, except for oil and natural gas production properties as described below. Investments, consisting principally of securities held for corporate development purposes, are carried at cost which approximates market. 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 repurchase commitment is carried at Frontier Gas Storage Company's cost of purchased natural gas, less an allowance to reflect changed market conditions. Inventories Inventories, other than natural gas in underground storage, consist primarily of materials and supplies and inventory held for resale. These inventories are stated at the lower of average cost or market. Utility revenue and energy cost The company recognizes revenue each month based on the services provided to all customers during the month. Because meters for retail utility customers are read and billed on a monthly cycle billing basis, revenues (and related energy costs) are estimated and recorded for those services provided from the date which meters were last read to month end. Prior to 1993, the company recorded revenue and the cost of purchased natural gas sold when customers were billed. See Note 2 for a discussion of an accounting change in the company's revenue recognition method made effective January 1, 1993. Natural gas costs recoverable through rate adjustments Under the terms of certain orders of the public service commissions of Montana, North Dakota, South Dakota and Wyoming, 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 Effective with the adoption of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109) on January 1, 1993, as further described in Note 2, the company is providing deferred federal and state income taxes on all temporary differences. Prior to 1993, the company provided deferred federal and state income taxes on all non-utility timing differences and on all FERC jurisdictional utility timing differences. With respect to state jurisdictions, deferred federal and state income taxes were provided on utility timing differences only as permitted for ratemaking purposes. 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 public service commissions of Montana, North Dakota, South Dakota and Wyoming. Cash flow information Cash expenditures for interest and income taxes were as follows: Years ended December 31, 1993 1992 1991 (In thousands) Interest, net of amount capitalized. . .$22,717 $25,578 $29,749 Income taxes . . . . . . . . . . . . . .$24,545 $21,577 $17,645 The company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Reclassifications Certain reclassifications have been made in the financial statements for 1992 and 1991 to conform to the 1993 presentation. Such reclassifications had no effect on net income or common stockholders' investment as previously reported. NOTE 2 Accounting Changes Revenue recognition On January 1, 1993, Montana-Dakota Utilities Co. (Montana-Dakota) changed its revenue recognition method to include the accrual of estimated unbilled revenues for electric and natural gas service. This change results in a better matching of revenues and expenses and is consistent with predominant industry practice. Prior to this change, Montana-Dakota, for both its electric and natural gas businesses, recognized revenues on a monthly cycle billing basis which recorded revenues when customers were billed. Unbilled utility revenues at December 31, 1993, aggregated $18.3 million and are included in "Receivables" in the company's consolidated balance sheets. The cumulative effect of this change on net income for the twelve months ended December 31, 1993, is presented net of applicable income taxes of $3,355,000. Postretirement benefits other than pensions On January 1, 1993, the company adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS No. 106). The company has elected to amortize the transition obligation of approximately $49 million at January 1, 1993, which represents the accumulated postretirement benefit obligation at the time of adoption, over 20 years as provided by SFAS No. 106. The company's annual cost for 1993 based on the provisions of SFAS No. 106 is approximately $7.5 million, including amortization of the transition obligation discussed above. However, substantially all of the amounts related to Montana- Dakota's and Williston Basin Interstate Pipeline Company's (Williston Basin) regulated operations reflecting the difference between the 1993 SFAS No. 106 required accruals of approximately $6.0 million and the costs associated with the currently recoverable pay-as-you-go method, estimated to be approximately $2.0 million, are being deferred pursuant to regulatory orders received and are expected to be recovered in future rates charged to customers. See Note 15 for more information on the regulatory treatment of SFAS No. 106 costs. Accounting for income taxes On January 1, 1993, the company adopted SFAS No. 109. The company elected to record the cumulative effect on prior years in 1993 as allowed by SFAS No. 109, with such amount being immaterial to its financial position or results of operations. Excess deferred income tax balances associated with Montana-Dakota's and Williston Basin's rate-regulated activities have been recorded as a regulatory liability and are included in "Other deferred credits" in the company's consolidated balance sheets at December 31, 1993. This regulatory liability is expected to be reflected as a reduction in future rates charged customers in accordance with applicable regulatory procedures. NOTE 3 Pending Litigation Koch Hydrocarbon Company (Koch) On August 11, 1993, Koch and Williston Basin reached a settlement that terminated the litigation, as previously described in the 1992 Annual Report to Stockholders, with respect to all parties. The settlement, as to both the company and Williston Basin, satisfies all of Koch's claims for the past obligation, releases any claim with respect to obligations up to the present time and terminates any contractual arrangements with respect to the purchase of natural gas between the parties for the future. The settlement thus resolves both the past and the future obligation. In return, Williston Basin agreed to make an immediate cash payment to Koch of $40 million (inclusive of the $32 million awarded by the District Court in October 1991) and to transfer to Koch certain natural gas gathering facilities owned by Williston Basin having a cost, net of accumulated depreciation, of approximately $10.4 million. The company believes that it is entitled to recover from ratepayers most of the costs that were incurred as a result of this settlement. Since the amount of costs which can ultimately be recovered is subject to regulatory and market uncertainties, the company has provided reserves which it believes are adequate for any amounts that may not be recovered. Williston Basin expects to recover $8.3 million in settlement costs through its purchased gas cost adjustment recovery mechanism. See "Producer settlement cost recovery" and "Order 636" contained in Note 4 for a discussion of Williston Basin's filings under the FERC's Orders 500 and 636, respectively, requesting recovery of the balance of the costs associated with the Koch settlement. KN Energy, Inc. (KN) In May 1991, KN, a pipeline for whom Williston Basin transports natural gas, filed suit against Williston Basin in Federal District Court for the District of Montana. KN alleges, in part, that Williston Basin breached its contract with KN by failing to provide priority transportation for KN, and by charging KN transportation rates which were excessive. KN also alleges that Williston Basin is responsible for any take-or-pay costs it may incur as a result of the breach. Although no amount of damages was specified, KN asked the Court to order Williston Basin to reimburse KN for damages and certain other costs it has incurred along with requiring specific performance pursuant to the contract. Williston Basin filed a motion for summary judgment with the Court in August 1992, requesting that the Court dismiss KN's suit on the basis that these matters are more appropriate for FERC resolution. In September 1992, the Court denied Williston Basin's motion for summary judgment, but suspended the proceedings before it and referred these matters to the FERC. If the FERC is not able to ultimately resolve this dispute, both KN and Williston Basin can request reconsideration by the Court at that time. As of the present time, KN has not requested further action by the FERC. Although no assurances can be provided, based on previous FERC decisions, Williston Basin believes that the ultimate outcome of this matter will not be material to its financial position or results of operations. NOTE 4 Regulatory Matters and Revenues Subject to Refund General rate proceedings Williston Basin has pending two general natural gas rate change applications filed in 1989 and 1992 and has implemented these changed rates subject to refund. Williston Basin is awaiting final orders from the FERC. Reserves have been provided for a portion of the revenues collected subject to refund with respect to pending regulatory proceedings and for the recovery of certain producer settlement buy-out/buy-down costs as discussed below 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. Producer settlement cost recovery In June 1990, Williston Basin filed to recover 75 percent of $43.4 million ($32.6 million) in buy-out/buy-down costs under the alternate take-or-pay cost recovery mechanism embodied in Order 500. As permitted under Order 500, Williston Basin elected to recover 25 percent or $10.8 million of such costs through a direct surcharge to its sales customers, substantially all of which has been received, with an equal amount being charged to second quarter 1990 earnings. Williston Basin elected to recover the remaining 50 percent ($21.7 million) through a commodity sales rate surcharge. In July 1990, the FERC issued an order requiring Williston Basin to recalculate its surcharge and apply it to total throughput. Through December 31, 1993, Williston Basin has collected $23.6 million, including interest, of these costs through its commodity sales and transportation rate surcharges. In November 1990, Williston Basin appealed this order to the U.S. Court of Appeals for the D.C. Circuit. Oral argument before the Court was held in November 1991. In July 1992, the Court issued its order denying Williston Basin's appeal and remanding certain aspects of the case to the FERC. On May 6, 1993, the FERC issued an order on those issues remanded by the Court. The principal issue addressed by this order involved the exemption of one of Williston Basin's major transportation customers from the assessment of take-or- pay surcharges. Williston Basin made a filing seeking authority to reallocate these costs to its other customers, which the FERC approved. On August 26, 1993, Williston Basin filed to recover 75 percent of $28.7 million ($21.5 million) in buy-out/buy-down costs paid to Koch as part of a lawsuit settlement under the alternate take-or-pay cost recovery mechanism embodied in Order 500. As permitted under Order 500, Williston Basin elected to recover 25 percent or $7.2 million of such costs through a direct surcharge to sales customers, substantially all of which has been received. In addition, through reserves previously provided, Williston Basin has absorbed an equal amount. Williston Basin elected to recover the remaining 50 percent ($14.3 million) through a throughput surcharge applicable to both sales and transportation. Williston Basin began collecting these costs, subject to refund, on October 1, 1993, pending the outcome of future hearings in mid-1994. Order 636 In April 1992, the FERC issued Order 636, which requires fundamental changes in the way natural gas pipelines do business. Under Order 636, pipelines are required to offer unbundled transportation service, with the transportation customer having the option of purchasing gas from other suppliers. Pipelines are also required to provide "equivalent" transportation services for all customers regardless of whether they are purchasing gas from such pipeline or other suppliers. As a part of Order 636, the FERC acknowledged that incremental costs may be required in the transition to the FERC-mandated service structures. Such costs include facility costs, gas supply contract restructuring and similar costs. Specific references concerning the allowed recovery of such costs are included in the final rule. In addition, Order 636 changes the rate design methodology used for pipeline transportation to the straight fixed variable (SFV) method. Under the SFV approach, all fixed storage and transmission costs, including return on equity and associated taxes, are included in the demand charge (a fixed monthly charge) and all variable costs are recovered through a commodity charge based on volumes transported. Under SFV, pipelines should be able to recover all fixed costs properly allocable to firm transportation regardless of how much gas is actually transported. Also included in Order 636 were guidelines addressing abandonment of services, capacity release and/or assignment of firm capacity rights. In October 1992, Williston Basin filed a revised tariff with the FERC designed to comply with Order 636. The revised tariff reflected the cost allocation and rate design necessary to the unbundling of Williston Basin's current services. The FERC issued an order on February 12, 1993, in which it accepted Williston Basin's filing subject to certain conditions. On March 15, 1993, Williston Basin filed further tariff revisions with the FERC in compliance with the FERC's February 12, 1993, order, and on March 12, 1993, filed for rehearing and/or clarification of other matters raised in the February 12, 1993, order. On May 13, 1993, the FERC issued an order addressing both Williston Basin's rehearing request and its March 15 tariff filing. A significant issue addressed by the FERC's order was a determination that certain natural gas in underground storage which was determined to be excess upon the future implementation of Order 636 must be sold at market prices. The order further required that the profit from such sale be used to offset any transition costs. Williston Basin requested rehearing of this and other issues by the FERC. An appeal was filed by Williston Basin on June 30, 1993, with the U.S. Court of Appeals for the D.C. Circuit related to, among other things, the FERC allowing firm transportation customers flexible receipt and delivery points anywhere on Williston Basin's pipeline system upon implementation of Order 636. On September 17, 1993, the FERC issued its order authorizing Williston Basin's implementation of Order 636 tariffs effective November 1, 1993. As a part of this order, the FERC reversed its May 13, 1993, determination related to the sale of certain natural gas in underground storage and ordered that this storage gas be offered for sale to Williston Basin's customers at its original cost. As a result, any profits which would have been realized on the sale at market prices of this storage gas will not reduce Williston Basin's Order 636 transition costs. Williston Basin requested rehearing of this issue by the FERC on the grounds that requiring the sale of this storage gas at cost results in a confiscation of its assets, which the FERC denied on December 16, 1993. Williston Basin has appealed the FERC's decisions to the U.S. Court of Appeals for the D.C. Circuit. On November 5, 1993, Williston Basin filed with the FERC, pursuant to the provisions of Order 636, revised tariff sheets requesting the recovery of $13.4 million of gas supply realignment transition costs (GSR costs) effective December 1, 1993. The GSR cost recovery being requested reflects costs paid to Koch as part of a lawsuit settlement, as previously described in Note 3, and does not include other GSR costs, if any, which may be incurred, and future recovery sought, by Williston Basin. This matter is currently pending before the FERC. Montana-Dakota has also filed revised gas cost tariffs with each of its four state regulatory commissions reflecting the effects of Williston Basin's November 1, 1993, implementation of Order 636. In October 1993, all four state regulatory commissions approved the revised tariffs. Although no assurances can be provided, the company believes that Order 636 will not have a significant effect on its financial position or results of operations. NOTE 5 Natural Gas Repurchase Commitment The company has offered for sale since 1984 the 61 million decatherms (MMdk) of inventoried natural gas owned by Frontier Gas Storage Company (Frontier), a special purpose, non-affiliated corporation. Through an agreement, an obligation exists 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 through the issuance of commercial paper that has the credit support of an irrevocable $105 million letter of credit. At December 31, 1993, borrowings totalled $101.1 million at a weighted average interest rate of 3.5 percent. These transactions will terminate on November 30, 1995, unless terminated earlier by the occurrence of certain events. The FERC issued an order in July 1989, ruling on several cost-of- service issues reserved as a part of the 1985 corporate realignment. Addressed as a part of this order were certain rate design issues related to the permissible rates for the transportation of the natural gas held under the repurchase commitment. The issue relating to the cost of storing this gas was not decided by that order. As a part of orders issued in August 1990 and May 1991 related to a general rate increase application, the FERC held that storage costs should be allocated to this gas. Williston Basin's July 1991 refund related to a general rate increase application, reflected implementation of the above finding on a prospective basis only. The public service commissions of Montana and South Dakota and the Montana Consumer Counsel protested whether such storage costs should be allocated to the gas prospectively rather than retroactively to May 2, 1986. In October 1991, the FERC issued an order rejecting Williston Basin's compliance filing on the basis that, among other things, Williston Basin is required to allocate storage costs to this gas retroactive to May 2, 1986. Williston Basin requested rehearing of the FERC's order on this issue in November 1991. In February 1992, the FERC issued an order which reversed its October 1991 order and held that such storage costs be allocated to this gas on a prospective basis only, commencing March 6, 1992. A compliance filing was made with the FERC in March 1992, which the FERC approved on and with an effective date beginning May 20, 1992. These storage costs, as initially allocated to the Frontier gas, approximated $2.1 million annually and represent costs which Williston Basin may not recover. The issue regarding the applicability of assessing storage charges to the gas, which was appealed by Williston Basin to the U.S. Court of Appeals for the D.C. Circuit in July 1991, creates additional uncertainty as to the costs associated with holding this gas. In July 1992, the Court, at the FERC's request, returned the proceeding to the FERC for its further consideration. Beginning in October 1992, as a result of increases in natural gas prices, Williston Basin began to sell and transport a portion of the natural gas held under the repurchase commitment. Through December 31, 1993, 12.5 MMdk of this natural gas had been sold and transported by Williston Basin to off-system markets. Williston Basin will continue to aggressively market the remaining 48.3 MMdk of this natural gas as long as market conditions remain favorable. In addition, it will continue to seek long-term sales contracts. NOTE 6 Environmental Matters Montana-Dakota and Williston Basin discovered polychlorinated biphenyls (PCBs) in portions of their natural gas systems and informed the United States Environmental Protection Agency (EPA) in January 1991. Montana-Dakota and Williston Basin believe the PCBs entered the system from a valve sealant. Both Montana-Dakota and Williston Basin have initiated testing, monitoring and remediation procedures, in accordance with applicable regulations and the work plan submitted to the EPA and the appropriate state agencies. Costs incurred by Montana-Dakota and Williston Basin through December 31, 1993, to address this situation aggregated approximately $720,000. These costs are related to the testing being performed, and the costs to remove, dispose of and replace certain property found to be contaminated. On the basis of findings to date, Montana-Dakota and Williston Basin estimate that future environmental assessment and remediation costs that will be incurred range from $3 million to $15 million. This estimate depends upon a number of assumptions concerning the scope of remediation that will be required at certain locations, the cost of remedial measures to be undertaken and the time period over which the remedial measures are implemented. In a separate action, Montana-Dakota and Williston Basin filed suit in Montana State Court, Yellowstone County, in January 1991, against Rockwell International Corporation, manufacturer of the valve sealant, to recover any costs which may be associated with the presence of PCBs in the system, including a remediation program. On January 31, 1994, Montana-Dakota, Williston Basin and Rockwell reached a settlement which terminated this litigation. Pursuant to the terms of the settlement, Rockwell will reimburse Montana-Dakota and Williston Basin for a portion of certain remediation costs incurred or expected to be incurred. In addition, both Montana-Dakota and Williston Basin consider unreimbursed environmental remediation costs and costs associated with compliance with environmental standards to be recoverable through rates, since they are prudent costs incurred in the ordinary course of business and, accordingly, have sought and will continue to seek recovery of such costs through rate filings. Although no assurances can be given, based on the estimated cost of the remediation program and the expected recovery of most of these costs from third parties or ratepayers, Montana-Dakota and Williston Basin believe that the ultimate costs related to these matters will not be material to Montana-Dakota's or Williston Basin's financial position or results of operations. In mid-1992, Williston Basin discovered that several of its natural gas compressor stations had been operating without air quality permits. As a result, in late 1992, applications for permits were filed with the Montana Air Quality Bureau (Bureau), the agency for the state of Montana which regulates air quality. In March 1993, the Bureau cited Williston Basin for operating the compressors without the requisite air quality permits and further alleged excessive emissions by the compressor engines of certain air pollutants, primarily oxides of nitrogen and carbon monoxide. Williston Basin is currently engaged in further testing these air emissions but is currently unable to determine the costs that will be incurred to remedy the situation although such costs are not expected to be material to its financial position or results of operations. In June 1990, Montana-Dakota was notified by the EPA that it and several others were named as Potentially Responsible Parties (PRPs) in connection with the cleanup of pollution at a landfill site located in Minot, North Dakota. An informational meeting was held on January 20, 1993, between the EPA and the PRPs outlining the EPA's proposed remedy and the settlement process. On June 21, 1993, the EPA issued its decision on the selected remediation to be performed at the site. Based on the EPA's proposed remediation plan, current estimates of the total cleanup costs for all parties, including oversight costs, at this site range from approximately $3.7 million to $4.8 million. Montana-Dakota believes that it was not a material contributor to this contamination and, therefore, further believes that its share of the liability for such cleanup will not have a material effect on its results of operations. NOTE 7 Natural Gas in Underground Storage Natural gas in underground storage included in natural gas transmission property, plant and equipment amounted to approximately $49 million at December 31, 1993, $51 million at December 31, 1992 and $53 million at December 31, 1991. In addition, $1.3 million, $3.7 million and $3.6 million at December 31, 1993, 1992 and 1991, respectively, of natural gas in underground storage is included in inventories. NOTE 8 Short-term Borrowings The company and its subsidiaries had unsecured lines of credit from several banks totalling $86 million at December 31, 1993, $80 million at December 31, 1992 and $73 million at December 31, 1991. 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 $9.5 million at December 31, 1993 and $7.8 million at December 31, 1992, with no amounts outstanding at December 31, 1991. The unused portions of the lines of credit are subject to withdrawal based on the occurrence of certain events. NOTE 9 Common Stock 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-hundredth of a share of Series A preference stock, without par value, at a purchase price of $50, 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 common stock of the acquiring person having a market value of twice the exercise price of the right. The rights, which expire in November 1998, are redeemable in whole, but not in part, at the company's option at any time for a price of $.02 per right. There have been no changes in the amounts outstanding for common stock and other paid in capital during the years ended December 31, 1993, 1992 and 1991. The company's Dividend Reinvestment Plan (DRIP) provides holders of all classes of the company's capital stock the opportunity to invest their cash dividends in shares of common stock and to make optional cash payments of up to $5,000 per quarter for the same purpose. The company's Tax Deferred Compensation Savings Plans pursuant to Section 401(k) of the Internal Revenue Code are funded with common stock and also participate in the DRIP. Since January 1, 1989, these plans have been funded by the purchase of shares of common stock on the open market. However, shares of authorized but unissued common stock may be used for this purpose. At December 31, 1993, there were 1,020,229 shares of common stock reserved for issuance under the plans. NOTE 10 Retained Earnings Changes in retained earnings for the years ended December 31, 1993, 1992 and 1991 are as follows: 1993 1992 1991 (In thousands) Balance at beginning of year . . . . . .$144,319 $137,472 $127,914 Net income . . . . . . . . . . . . . . . 44,338 35,371 38,017 188,657 172,843 165,931 Deduct: Dividends declared -- Preferred stocks at required annual rates . . . . . . . . . . . 802 807 812 Common stock . . . . . . . . . . . . 28,857 27,717 27,243 29,659 28,524 28,055 Settlement costs associated with repurchase of preferred stocks . . . --- --- 404 Balance at end of year . . . . . . . . .$158,998 $144,319 $137,472 NOTE 11 Preferred Stocks The preferred stocks outstanding are subject to redemption, in whole or in part, at the option of the company with certain limitations on 30 days notice on any quarterly dividend date. The company is obligated to make annual sinking fund contributions to retire the 5.10% Series preferred stock. The redemption prices and sinking fund requirements, where applicable, are summarized below: Redemption Sinking Fund Series Price (a) Shares Price (a) Preferred stock: 4.50%. . . . . . . . . . . .$105.00 (b) --- --- 4.70%. . . . . . . . . . . .$102.00 (b) --- --- 5.10%. . . . . . . . . . . .$102.00 1,000 (c) $100.00 (a) Plus accrued dividends. (b) These series are redeemable at the sole discretion of the company. (c) Annually on December 1, if tendered. In the event of a voluntary or involuntary liquidation, all preferred stock series holders are entitled to $100 per share, plus accrued dividends. The aggregate annual sinking fund amount applicable to preferred stock subject to mandatory redemption requirements for each of the five years following December 31, 1993, is $100,000. NOTE 12 Long-term Debt and Indenture Provisions First mortgage bonds and notes outstanding at December 31 are as follows: 1993 1992 1991 (In thousands) 7 1/8% Series, due Nov. 1, 1993. . . .$ --- $ --- $ 9,400 8 5/8% Series, due Oct. 1, 2001. . . . --- --- 9,400 9 1/4% Series, due Sept. 15, 2003. . . --- --- 9,400 9 3/8% Series, due Nov. 15, 2011 . . . --- --- 75,200 9 1/8% Series, due May 15, 2006. . . . 50,000 50,000 50,000 9 1/8% Series, due Oct. 1, 2016. . . . 20,000 20,000 20,000 7 5/8% Sinking Fund, due Oct. 15, 1992 --- --- 1,000 8 1/2% Sinking Fund, due Oct. 1, 1996. --- --- 2,500 9% Sinking Fund, due Sept. 15, 1998. . --- --- 3,500 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 -- 5.80%, due Apr. 1, 1994. . . . . . . 15,000 15,000 --- 6.30%, due Apr. 1, 1995. . . . . . . 10,000 10,000 --- 6.95%, due Apr. 1, 1996. . . . . . . 10,000 10,000 --- 7.20%, due Apr. 1, 1997. . . . . . . 5,000 5,000 --- 8.25%, due Apr. 1, 2007. . . . . . . 30,000 30,000 --- 8.60%, due Apr. 1, 2012. . . . . . . 35,000 35,000 --- Total first mortgage bonds and notes. . . . . . . . . . . . . $195,850 $195,850 $180,400 The company has a revolving credit and term loan agreement which totalled $30 million at December 31, 1993, 1992 and 1991. Amounts outstanding under this agreement were $30 million at December 31, 1993 and 1992, respectively, and $10.5 million at December 31, 1991. Fidelity Oil Co. has $15 million outstanding under a senior secured note at December 31, 1993. In addition, Fidelity Oil Co. has available $20 million under a secured line of credit, $1.5 million of which was outstanding at December 31, 1993. At December 31, 1992, Fidelity Oil Co. had a secured line of credit which totalled $35 million, of which $19.4 million was outstanding. However, on January 13, 1993, $15 million of the line was converted to a senior secured note. Fidelity Oil Co. had available $15 million under a revolving credit and term loan agreement at December 31, 1991, $6.4 million of which was outstanding. The amounts of long-term debt maturities and sinking fund requirements for the five years following December 31, 1993, (net of prepayments) aggregate $15.2 million in 1994; $10.7 million in 1995; $40.7 million in 1996; $14.7 million in 1997 and $9.6 million in 1998. Substantially all of the company's retail utility property is subject to the lien of its Indenture of Mortgage. Under the terms and conditions of such Indenture, the company could have issued approximately $153 million of additional first mortgage bonds at December 31, 1993. Certain natural gas transmission property is subject to purchase money mortgages payable by Williston Basin to the company. In December 1991, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 107, "Disclosures about Fair Value of Financial Instruments" (SFAS No. 107). SFAS No. 107 establishes fair value disclosure practices for certain financial instruments. The fair value of the company's first mortgage bonds and notes at December 31, 1993, is approximately $216 million. However, the difference between the recorded value of the company's other debt instruments as well as investments in certain securities and their fair values were not material. NOTE 13 Income Taxes Income tax expense is summarized as follows: 1993 1992 1991 (In thousands) Current -- Federal. . . . . . . . . . . . . . . $25,665 $ 18,272 $14,287 State. . . . . . . . . . . . . . . . 3,997 3,359 2,972 Foreign. . . . . . . . . . . . . . . 10 --- --- 29,672 21,631 17,259 Deferred -- Investment tax credit -- net . . . . (1,144) (1,183) (1,236) Income taxes: Federal. . . . . . . . . . . . . . (9,560) (8,505) 722 State. . . . . . . . . . . . . . . 1,014 (1,043) 63 (9,690) (10,731) (451) Total income tax expense . . . . . . . $19,982 $ 10,900 $16,808 Components of deferred tax assets and deferred tax liabilities recognized in the company's consolidated balance sheets are as follows: 1993 (In thousands) Deferred tax assets: Reserves for regulatory matters . . . . . . . . . . . . . $ 40,195 Natural gas available under repurchase commitment . . . . 7,554 Deferred investment tax credits . . . . . . . . . . . . . 4,462 Accrued land reclamation. . . . . . . . . . . . . . . . . 4,017 Accrued pension costs . . . . . . . . . . . . . . . . . . 3,676 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 6,428 Total deferred tax assets. . . . . . . . . . . . . . . . . $ 66,332 Deferred tax liabilities: Depreciation and basis differences on property, plant and equipment . . . . . . . . . . . . . . . . . . $108,846 Basis differences on oil and natural gas producing properties. . . . . . . . . . . . . . . . . . 15,889 Natural gas contract settlement and restructuring costs . . . . . . . . . . . . . . . . . . 13,530 Long-term debt refinancing costs. . . . . . . . . . . . . 5,223 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 4,078 Total deferred tax liabilities . . . . . . . . . . . . . . $147,566 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: 1993 1992 1991 Amount % Amount % Amount % (Dollars in thousands) Computed tax at federal statutory rate . . . . $20,580 35.0 $15,732 34.0 $18,640 34.0 Increases (reductions) in provision for taxes resulting from: Depletion allowance. . (1,424) (2.4) (1,393) (3.0) (1,433) (2.6) State income taxes -- net of federal income tax benefit. . . . . . . 2,171 3.7 1,664 3.6 1,949 3.6 Tax-exempt interest. . (725) (1.2) (958) (2.1) (1,174) (2.1) Investment tax credit amortization . . . . (1,144) (2.0) (1,183) (2.5) (1,236) (2.3) Other items. . . . . . 524 .9 (2,962) (6.4) 62 .1 Actual taxes . . . . . . $19,982 34.0 $10,900 23.6 $16,808 30.7 During 1992 and 1991, deferred income tax expense resulted from differences in the timing of recognizing certain revenues and expenses for tax and financial statement purposes. The sources of these differences and the tax effect of each are as follows: 1992 1991 (In thousands) Tax over book depreciation . . . . . . . . . . . $ 1,426 $ 1,834 Natural gas costs recoverable through rate adjustments . . . . . . . . . . . . . . . 1,478 (1,562) Natural gas contract settlement and restructuring. . . . . . . . . . . . . . . . . (2,533) (3,028) Reserves for regulatory matters. . . . . . . . . (7,270) (2,261) Unbilled utility revenue . . . . . . . . . . . . (1,778) 1,093 Well drilling and development costs. . . . . . . 2,343 3,797 Land reclamation and other . . . . . . . . . . . (3,214) 912 Total deferred income tax expense. . . . . . . . $(9,548) $ 785 The company's consolidated federal income tax returns were under examination by the Internal Revenue Service (IRS) for the tax years 1983 through 1988. In September 1991, the company received a deficiency notice from the IRS for the tax years 1983 through 1985 which proposed substantial additional income taxes, plus interest. In an alternative position contained in the notice of proposed deficiency, the IRS is claiming a lower level of taxes due, plus interest as well as penalties. In May 1992, a similar notice of proposed deficiency was received for the years 1986 through 1988. Although the notices of proposed deficiency encompass a number of separate issues, the principal issue is related to the tax treatment of deductions claimed in connection with certain investments made by Knife River and Fidelity Oil. The company's tax counsel has issued opinions related to the principal issue discussed above, stating that it is more likely than not that the company would prevail in this matter. Thus, the company intends to contest vigorously the deficiencies proposed by the IRS and, in that regard, has timely filed protests for the 1983 through 1988 tax years contesting the treatment proposed in the notices of proposed deficiency. If the IRS position were upheld, the resulting deficiencies would have a material effect on results of operations. NOTE 14 Business Segment Data The company's operations are conducted through five business segments. The electric, natural gas distribution, natural gas transmission, mining and construction materials, 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 page one. Segment operating information at December 31, 1993, 1992 and 1991, is presented in the Consolidated Statements of Income. Other segment information is presented below: 1993 1992 1991 (In thousands) Depreciation, depletion and amortization -- Electric . . . . . . . . . . . . .$ 15,307 $ 15,132 $ 15,698 Natural gas distribution . . . . . 5,114 4,809 4,673 Natural gas transmission . . . . . 7,113 6,409 6,110 Mining and construction materials . . . . . . . . . . . . 5,594 4,527 4,035 Oil and natural gas production . . 12,034 8,817 6,061 Total depreciation, depletion and amortization . . . . . . .$ 45,162 $ 39,694 $ 36,577 Investment information -- Identifiable assets: Electric (a) . . . . . . . . . .$ 306,179 $ 301,959 $302,296 Natural gas distribution (a) . . 104,013 90,979 84,250 Natural gas transmission (a) . . 383,355 404,250 391,735 Mining and construction materials. . . . . . . . . . . 120,105 105,761 102,760 Oil and natural gas production . . . . . . . . . . 89,690 80,128 61,935 Total identifiable assets. . . 1,003,342 983,077 942,976 Corporate assets (b) . . . . . . . 37,709 41,433 21,715 Total consolidated assets. . .$1,041,051 $1,024,510 $964,691 (a) Includes, in the case of natural gas distribution and electric property, allocations of common utility property. Natural gas stored or available under repurchase commitment is included in natural gas 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 7 percent of mining and construction materials revenues in 1993 (13 percent in 1992 and 16 percent in 1991) represent Knife River's direct sales of lignite coal to the company. The company's share of Knife River's sales for use at two generating stations jointly owned by the company and other utilities was approximately 10 percent of mining and construction materials revenues in 1993, 20 percent in 1992 and 19 percent in 1991. In May 1992, KRC Aggregate, Inc. (KRC Aggregate), an indirect, wholly-owned subsidiary of Knife River, entered into the sand and gravel business in central California through the purchase of certain properties, including mining and processing equipment. These operations, located near Lodi, California, surface mine, process and market aggregate products to various customers, including road and housing contractors, tile manufacturers and ready-mix plants, with a market area extending approximately 60 miles from the mine. On April 2, 1993, the assets of Alaska Basic Industries, Inc. (ABI) and its subsidiaries were purchased by KRC Aggregate. ABI is a vertically integrated construction materials business headquartered in Anchorage, Alaska. ABI's nine divisions handle the sale of its sand and gravel aggregates and related products such as ready-mixed concrete, asphalt and finished aggregate products. Effective September 1, 1993, KRC Aggregate, purchased the stock of LTM, Incorporated (LTM), Rogue Aggregates, Inc. (Rogue) and Concrete, Inc., construction materials subsidiaries of Terra Industries. Headquartered in Medford, Oregon, LTM and Rogue are vertically integrated construction materials businesses serving southern Oregon markets. Their products include sand and gravel aggregates, ready- mixed concrete, asphalt and finished aggregate products. Concrete, Inc., headquartered in Stockton, California, operates four ready-mix plants in San Joaquin County. These ready-mix plants became part of KRC Aggregate's Lodi, California operations. Pro forma amounts reflecting the effects of the above acquisitions are not disclosed as such acquisitions were not material to the company's financial position or results of operations. NOTE 15 Employee Benefit Plans The company has noncontributory defined benefit pension plans covering substantially all full-time employees. Pension benefits are based on employee's years of service and earnings. The company makes annual contributions to the plans consistent with the funding requirements of federal law and regulations. Pension expense is summarized as follows: 1993 1992 1991 (In thousands) Service cost/benefits earned during the year . . . . . . . . . . . . . .$ 3,277 $ 2,957 $ 2,803 Interest cost on projected benefit obligation . . . . . . . . . . . . . 9,488 8,464 8,008 Loss (return) on plan assets . . . . . (14,540) (11,384) (25,822) Net amortization and deferral. . . . . 2,916 491 15,637 Total pension costs. . . . . . . . . . 1,141 528 626 Less amounts capitalized . . . . . . . 133 75 58 Total pension expense. . . . . . . . .$ 1,008 $ 453 $ 568 The funded status of the company's plans is summarized as follows: 1993 1992 1991 (In thousands) Projected benefit obligation: Vested . . . . . . . . . . . . . . $108,718 $ 92,623 $ 81,766 Nonvested. . . . . . . . . . . . . 4,696 3,251 2,820 Accumulated benefit obligation . . . 113,414 95,874 84,586 Provision for future pay increases . 26,379 22,614 20,794 Projected benefit obligation . . . . . 139,793 118,488 105,380 Plan assets at market value. . . . . . 149,184 140,623 135,172 (9,391) (22,135) (29,792) Plus: Unrecognized transition asset. . . . 10,305 11,295 12,284 Unrecognized net gains and prior service costs. . . . . . . . . . . 4,953 16,018 22,157 Accrued pension costs. . . . . . . . . $ 5,867 $ 5,178 $ 4,649 The projected benefit obligation was determined using an assumed discount rate of 7 percent (8 percent in 1992 and 1991) and assumed long-term rates for estimated compensation increases of 4 1/2 percent (5 percent in 1992 and 5 1/2 percent in 1991). The change in these assumptions had the effect of increasing the projected benefit obligation at December 31, 1993, by $15 million. The assumed long-term rate of return on plan assets is 8 1/2 percent. Plan assets consist primarily of debt and equity securities. In addition to providing pension benefits, the company has a policy of providing all eligible employees and dependents certain other postretirement benefits which include health care and life insurance upon their retirement. The plans underlying these benefits may require contributions by the employee depending on such employee's age and years of service at retirement or the date of retirement. The accounting for the health care plan anticipates future cost-sharing changes that are consistent with the company's expressed intent to increase retiree contributions each year by the excess of the expected health care cost trend rate over 6 percent. Postretirement benefits expense is summarized as follows: 1993 (In thousands) Service cost/benefits earned during the year . . . . . . . . $1,098 Interest cost on accumulated postretirement benefit obligation . . . . . . . . . . . . . . . . . . . . 3,932 Amortization of transition obligation. . . . . . . . . . . . 2,458 Total postretirement benefits expense. . . . . . . . . . . . $7,488 The funded status of the company's plans is summarized as follows: 1993 (In thousands) Accumulated postretirement benefit obligation: Retirees eligible for benefits . . . . . . . . . . . . . . $31,029 Active employees not fully eligible. . . . . . . . . . . . 28,592 Total. . . . . . . . . . . . . . . . . . . . . . . . . . 59,621 Plan assets at market value. . . . . . . . . . . . . . . . . 4,450 55,171 Less: Unrecognized transition obligation . . . . . . . . . . . . 46,694 Unrecognized net losses. . . . . . . . . . . . . . . . . . 7,992 Accrued postretirement benefits cost . . . . . . . . . . . . $ 485 The health care cost trend rate assumed in determining the accumulated postretirement benefit obligation was 12 percent in 1993, decreasing by 1 percent per year until an ultimate rate of 6 percent is reached in 1999 and remaining level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. To illustrate, increasing the assumed health care cost trend rates by 1 percent each year would increase the accumulated postretirement benefit obligation as of December 31, 1993, by $3.6 million and the aggregate of the service and interest cost components of postretirement benefits expense by $288,000. The accumulated postretirement benefit obligation was determined using an assumed discount rate of 7 percent (8 percent at January 1, 1993, the date of adoption) and assumed long-term rates for estimated compensation increases, as they apply to life insurance benefits, of 4 1/2 percent (5 1/2 percent at January 1, 1993). The change in these assumptions had the effect of increasing the accumulated postretirement benefit obligation at December 31, 1993, by $8 million. The assumed long-term rate of return on assets is 7 1/2 percent. Plan assets at December 31, 1993,consist primarily of short-term investments. The company's accounting recognition and funding policy as it applies to postretirement benefits, will depend, in part, on the position of applicable regulatory bodies with respect to recovery of such costs for its regulated businesses. Montana-Dakota filed applications with the public service commissions of Montana, North Dakota, South Dakota and Wyoming requesting that the commissions adopt the principles of accrual accounting for these costs and that the company be permitted to defer, on a limited basis, the difference between the SFAS No. 106 required accruals and the costs associated with the presently used pay-as-you-go method until such time that the full SFAS No. 106 expense is allowed in the company's rates charged to its customers. The company has received an order from the Montana Public Service Commission authorizing such deferrals. The public service commissions of North Dakota and Wyoming, as a part of orders issued in 1993 related to general rate applications filed by Montana- Dakota, adopted accrual accounting for ratemaking purposes and generally require that these benefits be funded through an external trust using the most tax-effective funding options available. However, as a part of a 1993 general rate proceeding, the South Dakota commission deferred this issue until commission hearings are held in March 1994, and has continued the use of pay-as-you-go accounting for ratemaking purposes until that date. The FERC, in a policy statement issued in December 1992, has adopted accrual accounting for these costs for ratemaking purposes and has authorized limited deferral of the higher accrual costs. Williston Basin expects to seek recovery of these costs in its next general rate proceeding. 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 in 1993 was $1.4 million. The company has a Key Employee Stock Option Plan under which the company is authorized to grant options for up to 800,000 shares of common stock with an option price equal to market value on the date of grant. At December 31, 1993, 183,040 options, with an average option price of $23.72 per share, were outstanding, none of which were exercisable. The company has contributed $3.2 million to a trust established to fund its commitment under the Plan. The company has Tax Deferred Compensation Savings Plans for eligible employees. Each participant may contribute amounts up to 10 percent of eligible compensation, subject to certain limitations. The company contributes an amount equal to 50 percent of the participant's savings contribution up to a maximum of 6 percent of such participant's contribution. Company contributions were $1.7 million in 1993, $1.5 million in 1992 and $1.3 million in 1991. NOTE 16 Jointly Owned Facilities The consolidated financial statements include the company's 22.7 percent and 25.0 percent ownership interests in the assets, liabilities and expenses of the Big Stone Station and the Coyote Station, respectively. Each owner of the Big Stone and Coyote stations is responsible for providing its own financing of its investment in the jointly owned facilities. The company's share of the Big Stone Station and Coyote Station operating expenses is reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income. At December 31, the company's share of the cost of utility plant in service and related accumulated depreciation for the stations was as follows: 1993 1992 1991 (In thousands) Big Stone Station -- Utility plant in service . . . . . $ 47,349 $ 46,398 $ 46,783 Accumulated depreciation . . . . . 24,663 23,326 22,105 $ 22,686 $ 23,072 $ 24,678 Coyote Station -- Utility plant in service . . . . . $121,380 $121,294 $120,085 Accumulated depreciation . . . . . 42,482 39,129 35,474 $ 78,898 $ 82,165 $ 84,611 NOTE 17 Quarterly Data (Unaudited) The following unaudited information shows selected items by quarter for the years 1993 and 1992: First Second Third Fourth Quarter Quarter Quarter Quarter 1993 (In thousands, except per share amounts) Operating revenues . . . . . $124,169 $88,995 $98,832 $127,616 Operating expenses . . . . . 92,631 76,378 84,266 102,245 Operating income . . . . . . 31,538 12,617 14,566 25,371 Income before cumulative effect of accounting change 15,761 3,797 6,309 12,950 Cumulative effect of accounting change. . . . . 5,521 --- --- --- Net income . . . . . . . . . 21,282 3,797 6,309 12,950 Earnings per common share before cumulative effect of accounting change . . . .82 .19 .32 .67 Cumulative effect of accounting change per common share . . . . . . . .29 --- --- --- Earnings per common share. . 1.11 .19 .32 .67 Average common shares outstanding. . . . . . . . 18,985 18,985 18,985 18,985 1992 Operating revenues . . . . . $105,576 $78,839 $70,963 $106,797 Operating expenses . . . . . 81,793 66,181 57,756 79,386 Operating income . . . . . . 23,783 12,658 13,207 27,411 Net income . . . . . . . . . 11,440 4,018 5,174 14,739 Earnings per common share. . .59 .20 .26 .77 Average common shares outstanding. . . . . . . . 18,985 18,985 18,985 18,985 Pro forma amounts assuming retroactive application of accounting change: Net income . . . . . . . . $ 10,332 $ 3,507 $ 5,098 $ 16,915 Earnings per common share. .53 .17 .26 .88 Most of the company's operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate between 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 holds various oil and natural gas interests primarily through a series of working-interest agreements with several oil and natural gas producers and through operating agreements with Shell Western E & P, Inc. (Shell). Since 1986, Fidelity Oil has undertaken ventures, through a series of working-interest agreements with several different partners, that vary from the acquisition of producing properties with potential development opportunities to exploration and are located in the western United States, offshore in the Gulf of Mexico and in Canada. In these ventures, Fidelity Oil shares revenues and expenses from the development of specified properties in proportion to its investments. Fidelity Oil has net proceeds interests in the production of oil and natural gas and has an operating agreement (Agreement) with Shell applicable to certain of its acreage interests. Pursuant to the Agreement, Shell, as operator, controls all development, production, operations and marketing applicable to such acreage. As a net proceeds interest owner, Fidelity Oil is entitled to proceeds only when a particular unit has reached payout status. The following information includes Fidelity Oil's proportionate share of all its oil and natural gas net proceeds and working interests. The following table sets forth capitalized costs and related accumulated depreciation, depletion and amortization related to oil and natural gas producing activities at December 31: 1993 1992 1991 (In thousands) Subject to amortization. . . . . . . . $114,572 $91,058 $66,501 Not subject to amortization. . . . . . 2,022 2,383 1,533 Total capitalized costs. . . . . . . . 116,594 93,441 68,034 Accumulated depreciation, depletion and amortization . . . . . . . . . . 36,084 24,083 15,374 Net capitalized costs. . . . . . . . . $ 80,510 $69,358 $52,660 Capital expenditures, including those not subject to amortization, related to oil and natural gas producing activities for the 12 months ended December 31 are as follows: 1993 1992 1991 (In thousands) Acquisitions . . . . . . . . . . . . . $ 9,296 $ 9,976 $ 4,667 Exploration. . . . . . . . . . . . . . 7,787 11,074 7,781 Development . . . . . . . . . . . . . 7,836 4,715 9,824 Total capital expenditures . . . . . . $24,919 $25,765 $22,272 The following summary reflects income resulting from the company's operations of oil and natural gas producing activities, excluding corporate overhead and financing costs, for the 12 months ended December 31: 1993 1992 1991 (In thousands) Revenues . . . . . . . . . . . . . . . $39,125 $33,797 $33,939 Production costs . . . . . . . . . . . 13,700 13,965 14,040 Depreciation, depletion and amortization . . . . . . . . . . . . 11,998 8,782 6,027 Pretax income. . . . . . . . . . . . . 13,427 11,050 13,872 Income tax expense . . . . . . . . . . 4,606 3,658 4,745 Results of operations for producing activities . . . . . . . . $ 8,821 $ 7,392 $ 9,127 The following table summarizes the company's estimated quantities of proved developed oil and natural gas reserves at December 31, 1993, 1992 and 1991 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. 1993 1992 1991 Natural Natural Natural Oil Gas Oil Gas Oil Gas (In thousands of barrels/Mcf) Proved developed and undeveloped reserves: Balance at beginning of year. . . . . . . 12,200 37,200 11,600 27,500 12,400 16,100 Production . . . . . . (1,500)(8,800)(1,500)(5,000) (1,500)(2,600) Extensions and discoveries. . . . . 600 10,600 100 5,300 400 8,900 Purchases of proved reserves . . . . . . 500 9,200 900 8,200 200 5,700 Sales of reserves in place . . . . . . (300) (100) --- (100) --- (100) Revisions to previous estimates due to improved secondary recovery techniques and/or changed economic conditions. (300) 2,200 1,100 1,300 100 (500) Balance at end of year 11,200 50,300 12,200 37,200 11,600 27,500 Proved developed reserves: January 1, 1991. . . . 12,300 13,900 December 31, 1991. . . 11,200 22,600 December 31, 1992. . . 11,800 36,500 December 31, 1993. . . 11,100 43,100 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, 1993, applicable to the company's $7.1 million gross investment in oil and natural gas properties located in Canada comprise approximately 7 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: 1993 1992 1991 (In thousands) Future net cash flows before income taxes . . . . . . . . . . . . $119,800 $138,500 $94,300 Future income tax expenses . . . . . . 15,600 26,600 15,300 Future net cash flows. . . . . . . . . 104,200 111,900 79,000 10% annual discount for estimated timing of cash flows . . . . . . . . 32,600 35,200 24,900 Discounted future net cash flows relating to proved oil and natural gas reserves . . . . . . . . . . . . $ 71,600 $ 76,700 $54,100 The following are the sources of change in the standardized measure of discounted future net cash flows by year: 1993 1992 1991 (In thousands) Beginning of year. . . . . . . . . . . $ 76,700 $ 54,100 $ 68,000 Net revenues from production . . . . . (26,000) (19,700) (16,900) Change in net realization. . . . . . . (24,000) 13,100 (53,100) Extensions, discoveries and improved recovery, net of future production and development costs. . . . . . . . 16,800 8,200 12,900 Purchases of proved reserves . . . . . 14,100 16,000 7,100 Sales of reserves in place . . . . . . (1,600) (200) (300) Changes in estimated future development costs. . . . . . . . . . (11,600) (3,000) (5,000) Development costs incurred during the year. . . . . . . . . . . 7,800 4,700 9,800 Accretion of discount. . . . . . . . . 8,900 6,400 9,600 Net change in income taxes . . . . . . 6,000 (8,000) 18,200 Revisions of previous quantity estimates. . . . . . . . . . . . . . 4,400 5,000 3,600 Other. . . . . . . . . . . . . . . . . 100 100 200 Net change . . . . . . . . . . . . . . (5,100) 22,600 (13,900) End of year. . . . . . . . . . . . . . $ 71,600 $ 76,700 $ 54,100 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. Supplementary information with respect to the company's natural gas producing activities through Williston Basin is not included herein since the related production is anticipated to recover its equivalent cost of service. However, as a part of the settlement applicable to the corporate realignment in January 1985, the company agreed to adjust retail rates so as to limit flow-through of prices higher than cost of service to 50 percent of the excess. Based on the terms of the settlement, refunds for the 1991 and 1992 production years aggregating $1.0 million and $176,000, respectively, were made in the ensuing year. Estimated reserves associated with this gas are approximately 116,476 MMcf. The unamortized capitalized costs related to these reserves are approximately $7.9 million at December 31, 1993, $7.2 million at December 31, 1992, and $7.5 million at December 31, 1991. Non-depreciable capitalized costs are amortized on a composite unit-of-production method based on total estimated recoverable reserves and depreciable capitalized costs are amortized on a straight-line basis over the average useful life of the asset. In March and May 1993, Williston Basin was directed by the United States Minerals Management Service (MMS) to pay approximately $3.5 million, plus interest, in claimed royalty underpayments. These royalties are attributable to natural gas production by Williston Basin from federal leases in Montana and North Dakota for the period December 1, 1978, through February 29, 1988. Williston Basin has filed an administrative appeal with the MMS on this issue stating the gas was properly valued for royalty purposes. Williston Basin also believes that the statute of limitations limits this claim. Williston Basin is pursuing these issues before both the MMS and the courts. On December 21, 1993, Williston Basin received from the Montana Department of Revenue (MDR) an assessment claiming additional production taxes due of $3.7 million, plus interest, for 1988 through 1991 production. These claimed taxes result from the MDR's belief that certain natural gas production during the period at issue was not properly valued. Williston Basin does not agree with the MDR and has reached an agreement with the MDR that the appeal process be held in abeyance pending further review. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of MDU Resources Group, Inc.: We have audited the accompanying consolidated balance sheets and statements of capitalization of MDU Resources Group, Inc. (a Delaware corporation) and Subsidiaries as of December 31, 1993, 1992 and 1991, and the related consolidated statements of income and cash flows for each of the three years in the period ended December 31, 1993. 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, 1993, 1992 and 1991, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. As discussed in Note 2 to the consolidated financial statements, effective January 1, 1993, the company changed its methods of accounting for recording electric and natural gas distribution revenues, postretirement benefits other than pensions, and income taxes. /s/ Arthur Andersen & Co. Arthur Andersen & Co. Minneapolis, Minnesota, January 25, 1994 OPERATING STATISTICS MDU RESOURCES GROUP, INC.
1993 1992 1991 Selected Financial Data Operating revenues: (000's) Electric . . . . . . . . . . . . $ 131,109 $ 123,908 $128,708 Natural gas. . . . . . . . . . . 178,981 159,438 173,865 Mining and construction materials. . . . . . . . . . . 90,397 45,032 41,201 Oil and natural gas production . 39,125 33,797 33,939 $ 439,612 $ 362,175 $377,713 Operating income: (000's) Electric . . . . . . . . . . . . $ 30,520 $ 30,188 $ 34,647 Natural gas distribution . . . . 4,730 4,509 8,518 Natural gas transmission . . . . 20,108 21,331 19,904 Mining and construction materials. . . . . . . . . . . 16,984 11,532 9,682 Oil and natural gas production . 11,750 9,499 12,552 $ 84,092 $ 77,059 $ 85,303 Earnings (loss) on common stock: (000's) Electric . . . . . . . . . . . . $ 12,652* $ 13,302 $ 15,292 Natural gas distribution . . . . 1,182* 1,370 3,645 Natural gas transmission . . . . 4,713 3,479 449 Mining and construction materials. . . . . . . . . . . 12,359 10,662 9,809 Oil and natural gas production . 7,109 5,751 8,010 Earnings on common stock before cummulative effect of accounting change . . . . . 38,015* 34,564 37,205 Cumulative effect of accounting change. . . . . . . 5,521 --- --- $ 43,536 $ 34,564 $ 37,205 Earnings per common share before cumulative effect of accounting change. . . . . . . . $ 2.00* $ 1.82 $ 1.96 Cumulative effect of accounting change . . . . . . . . . . . . . .29 --- --- $ 2.29 $ 1.82 $ 1.96 Pro forma amounts assuming retroactive application of accounting change: Net income (000's) . . . . . . . $ 38,817 $ 35,852 $ 37,619 Earnings per common share. . . . $ 2.00 $ 1.85 $ 1.94 Common Stock Statistics Weighted average common shares outstanding (000's). . . . . . . 18,985 18,985 18,985 Dividends per common share . . . . $ 1.52 $ 1.46 $ 1.435 Book value per common share. . . . $ 16.76 $ 15.98 $ 15.62 Market price ratios: Dividend payout. . . . . . . . . 76%* 80% 73% Yield. . . . . . . . . . . . . . 5.0% 5.6% 5.8% Price/earnings ratio . . . . . . 15.8x* 14.5x 12.6x Market value as a percent of book value . . . . . . . . . . 188.0% 165.0% 157.7% Profitability Indicators Return on average common equity. . 12.3%* 11.6% 12.7% Return on average invested capital. . . . . . . . . . . . . 9.4%* 8.7% 9.6% Interest coverage. . . . . . . . . 3.4x* 3.3x 3.8x** Fixed charges coverage, including preferred dividends. . . . . . . 3.0x* 2.4x 2.4x General Total assets (000's) . . . . . . . $1,041,051 $1,024,510 $964,691 Net long-term debt (000's) . . . . $ 231,770 $ 249,845 $220,623 Redeemable preferred stock (000's) .$ 2,200 $ 2,300 $ 2,400 Capitalization ratios: Common stockholders' investment. 56% 53% 56% Preferred stocks . . . . . . . . 3 3 3 Long-term debt . . . . . . . . . 41 44 41 100% 100% 100% * Before cumulative effect of an accounting change reflecting the accrual of estimated unbilled revenues. ** Calculation reflects the provisions of the company's restatement of its Indenture of Mortgage effective April 1992.
OPERATING STATISTICS MDU RESOURCES GROUP, INC.
1990 1989 1988 Selected Financial Data Operating revenues: (000's) Electric . . . . . . . . . . . . $124,156 $126,228 $126,128 Natural gas. . . . . . . . . . . 151,599 159,703 168,125 Mining and construction materials. . . . . . . . . . . 38,276 41,643 42,388 Oil and natural gas production . 31,213 25,199 20,918 $345,244 $352,773 $357,559 Operating income: (000's) Electric . . . . . . . . . . . . $ 32,221 $ 32,592 $ 33,505 Natural gas distribution . . . . 6,578 7,781 5,368 Natural gas transmission . . . . 19,362 24,835 21,189 Mining and construction materials. . . . . . . . . . . 7,749 9,087 9,841 Oil and natural gas production . 12,523 10,420 7,352 $ 78,433 $ 84,715 $ 77,255 Earnings (loss) on common stock: (000's) Electric . . . . . . . . . . . . $ 14,280 $ 13,385 $ 13,444 Natural gas distribution . . . . 2,704 3,123 1,474 Natural gas transmission . . . . (7,578)* 3,722 2,320 Mining and construction materials. . . . . . . . . . . 9,632 8,890 11,493 Oil and natural gas production . 8,071 6,765 5,115 Earnings on common stock before cummulative effect of accounting change . . . . . 27,109* 35,885 33,846 Cumulative effect of accounting change. . . . . . . --- --- --- $ 27,109* $ 35,885 $ 33,846 Earnings per common share before cumulative effect of accounting change. . . . . . . . $ 1.43* $ 1.89 $ 1.81 Cumulative effect of accounting change . . . . . . . . . . . . . --- --- --- $ 1.43* $ 1.89 $ 1.81 Pro forma amounts assuming retroactive application of accounting change: Net income (000's) . . . . . . . $ 28,395* $ 36,861 $ 34,957 Earnings per common share. . . . $ 1.45 $ 1.90 $ 1.81 Common Stock Statistics Weighted average common shares outstanding (000's). . . . . . . 18,985 18,985 18,718 Dividends per common share . . . . $ 1.42 $ 1.47 $ 1.42 Book value per common share. . . . $ 15.12 $ 15.11 $ 14.75 Market price ratios: Dividend payout. . . . . . . . . 99%* 78% 78% Yield. . . . . . . . . . . . . . 6.9% 6.5% 7.5% Price/earnings ratio . . . . . . 14.3x* 12.0x 10.5x Market value as a percent of book value . . . . . . . . . . 135.6% 149.7% 128.8% Profitability Indicators Return on average common equity. . 9.4%* 12.5% 12.4% Return on average invested capital 7.8%* 9.2% 9.0% Interest coverage. . . . . . . . . 2.7x* 2.8x 2.7x Fixed charges coverage, including preferred dividends. . . . . . . 1.9x* 2.3x 2.2x General Total assets (000's) . . . . . . . $959,946 $971,401 $949,509 Net long-term debt (000's) . . . . $229,786 $234,333 $242,593 Redeemable preferred stock (000's) $ 2,500 $ 2,600 $ 3,100 Capitalization ratios: Common stockholders' investment. 54% 53% 52% Preferred stocks . . . . . . . . 3 3 3 Long-term debt . . . . . . . . . 43 44 45 100% 100% 100% * Reflects a $6.8 million or 36 cent per share after-tax effect of an absorption of certain natural gas contract litigation settlement costs. /TABLE OPERATING STATISTICS MDU RESOURCES GROUP, INC.
1993 1992 1991 Electric Operations Sales to ultimate consumers (thousand kWh) . . . . . . . . . . . .1,893,713 1,829,933 1,877,634 Sales for resale (thousand kWh). . . . . 510,987 352,550 331,314 Electric system generating and firm purchase capability -- kW (Interconnected system). . . . . . . . 465,200 460,200 454,400 Demand peak -- kW (Interconnected system). . . . . . . . 350,300 339,100 387,100 Electricity produced (thousand kWh) . . . . . . . . . . . .1,870,740 1,774,322 1,736,187 Electricity purchased (thousand kWh) . . . . . . . . . . . . 701,736 593,612 611,884 Cost of fuel and purchased power per kWh. . . . . . . . . . . . . $.016 $.016 $.016 Natural Gas Distribution Operations Sales (Mdk). . . . . . . . . . . . . . . 31,147 26,681 30,074 Transportation (Mdk) . . . . . . . . . . 12,704 13,742 12,261 Weighted average degree days -- % of previous year's actual . . . . . . . . 115% 98% 101% Natural Gas Transmission Operations Sales for resale (Mdk) . . . . . . . . . 13,201 16,841 19,572 Transportation (Mdk) . . . . . . . . . . 59,416 64,498 53,930 Natural gas: Produced (Mdk) . . . . . . . . . . . . 3,876 3,551 3,742 Purchased from others -- gross (Mdk) . 5,562 14,132 16,366 Stored (owned or controlled) Net injection (withdrawal)--MMcf . . (10,786) (2,931) (2,834) Cost of natural gas purchased per dk . . . . . . . . . . . . . . . . 1.78 $1.91 $2.07 Energy Marketing Operations Natural gas volumes (Mdk). . . . . . . . 6,827 3,292 991 Mining and Construction Materials Operations Coal: (000's) Tonnage sales. . . . . . . . . . . . . 5,066 4,913 4,731 Recoverable reserves in tons . . . . . 230,600 235,700 256,700 Construction materials: (000's) Aggregates (tons sold) . . . . . . . . 2,391 263 --- Ready-mixed concrete (cubic yards sold). . . . . . . . . . . . . 157 --- --- Asphalt (tons sold). . . . . . . . . . 141 --- --- Recoverable aggregate reserves in tons. . . . . . . . . . . . . . . 74,200 20,600 --- Oil and Natural Gas Production Operations Production: Oil (000's of barrels) . . . . . . . . 1,497 1,531 1,491 Natural gas (MMcf) . . . . . . . . . . 8,817 5,024 2,565 Average sales prices: Oil (per barrel) . . . . . . . . . . . $14.84 $16.74 $19.90 Natural gas (per Mcf). . . . . . . . . $ 1.86 $ 1.53 $ 1.48 Net recoverable reserves: Oil (000's of barrels) . . . . . . . . 11,200 12,200 11,600 Natural gas (MMcf) . . . . . . . . . . 50,300 37,200 27,500
OPERATING STATISTICS MDU RESOURCES GROUP, INC.
1990 1989 1988 Electric Operations Sales to ultimate consumers (thousand kWh). . . . . . . . . . . . 1,820,150 1,836,099 1,843,982 Sales for resale (thousand kWh). . . . 285,564 311,327 246,425 Electric system generating and firm purchase capability -- kW (Interconnected system). . . . . . . . 451,600 451,600 451,600 Demand peak -- kW (Interconnected system). . . . . . . . 381,600 383,600 386,700 Electricity produced (thousand kWh) . . . . . . . . . . . .1,674,648 1,773,849 1,691,778 Electricity purchased (thousand kWh) . . . . . . . . . . . . 573,099 557,650 598,443 Cost of fuel and purchased power per kWh. . . . . . . . . . . . . $.016 $.017 $.017 Natural Gas Distribution Operations Sales (Mdk). . . . . . . . . . . . . . . 28,278 31,643 32,557 Transportation (Mdk) . . . . . . . . . . 11,806 9,321 3,314 Weighted average degree days - % of previous year's actual . . . . . . . . 88% 112% 113% Natural Gas Transmission Operations Sales for resale (Mdk) . . . . . . . . . 19,658 27,274 33,515 Transportation (Mdk) . . . . . . . . . . 50,809 51,159 33,892 Natural gas: Produced (Mdk) . . . . . . . . . . . . 1,881 1,907 1,744 Purchased from others -- gross (Mdk) . 23,158 28,869 33,841 Stored (owned or controlled) Net injection (withdrawal)-- MMcf. . 2,782 (24) (41) Cost of natural gas purchased per dk . . . . . . . . . . . . . . . . $2.01 $1.68 $1.78 Energy Marketing Operations Natural gas volumes (Mdk). . . . . . . . 1,853 843 --- Mining and Construction Materials Operations Coal: (000's) Tonnage sales. . . . . . . . . . . . . 4,439 4,747 4,759 Recoverable reserves in tons . . . . . 261,500 266,000 270,800 Construction materials: (000's) Aggregates (tons sold) . . . . . . . . --- --- --- Ready-mixed concrete (cubic yards sold). . . . . . . . . . . . . --- --- --- Asphalt (tons sold). . . . . . . . . . --- --- --- Recoverable aggregate reserves in tons. . . . . . . . . . . . . . . --- --- --- Oil and Natural Gas Production Operations Production: Oil (000's of barrels) . . . . . . . . 1,374 1,348 1,358 Natural gas (MMcf) . . . . . . . . . . 1,846 1,605 1,464 Average sales prices: Oil (per barrel) . . . . . . . . . . . $20.11 $16.26 $13.43 Natural gas (per Mcf). . . . . . . . . $ 1.63 $ 1.66 $ 2.14 Net recoverable reserves: Oil (000's of barrels) . . . . . . . . 12,400 12,000 11,500 Natural gas (MMcf) . . . . . . . . . . 16,100 10,800 9,400
EX-21 4 SUBSIDIARIES FOR 10-K, EX-21 SUBSIDIARIES OF MDU RESOURCES GROUP, INC. December 31, 1993 State or Other Jurisdiction in Which Incorporated Alaska Basic Industries, Inc. Alaska Anchorage Sand and Gravel Company, Inc. Alaska Centennial Energy Holdings, Inc. Delaware Concrete, Inc. California Fidelity Oil Co. Delaware Fidelity Oil Holdings, Inc. Delaware Gwinner Propane, Inc. Delaware Knife River Coal Mining Company Minnesota KRC Aggregate, Inc. Delaware KRC Holdings, Inc. Delaware LTM, Incorporated Oregon Prairielands Energy Marketing, Inc. Delaware Rogue Aggregates, Inc. Oregon WBI Canadian Pipeline, Ltd. Canada Williston Basin Interstate Pipeline Company Delaware EX-23 5 CONSENT FOR 10-K, EX-23 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 25, 1994 included in the MDU Resources Group, Inc. Annual Report to Stockholders for 1993. We also consent to the incorporation of our reports included or 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. 33-66682, and on Form S-8, No. 2-96459, No. 33-54486, No. 33-53896 and No. 33-53898. It should be noted that we have not audited any financial statements of the Company subsequent to December 31, 1993 or performed any audit procedures subsequent to the date of our report. /s/ ARTHUR ANDERSEN & CO. ARTHUR ANDERSEN & CO. March 3, 1994 Minneapolis, Minnesota, CONSENT OF ENGINEER We hereby consent to the reference to our estimates dated January 10 and 17, 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. 33-66682, and on Form S-8, No. 2-96459, No. 33-54486, No. 33-53896 and No. 33-53898 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. March 3, 1994 Houston, Texas CONSENT OF ENGINEER We hereby consent to the reference to our report dated January 20, 1989, 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. 33-66682, and on Form S-8, No. 2-96459, No. 33-54486, No. 33-53896 and No. 33-53898 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/ PAUL WEIR COMPANY INCORPORATED PAUL WEIR COMPANY INCORPORATED March 3, 1994 Des Plaines, Illinois -----END PRIVACY-ENHANCED MESSAGE-----