SEC Info  
    Home      Search      My Interests      Help      Sign In      Please Sign In

Mdu Resources Group Inc – ‘10-K’ for 12/31/03

On:  Friday, 2/27/04, at 1:53pm ET   ·   For:  12/31/03   ·   Accession #:  67716-4-45   ·   File #:  1-03480

Previous ‘10-K’:  ‘10-K’ on 2/28/03 for 12/31/02   ·   Next:  ‘10-K’ on 2/23/05 for 12/31/04   ·   Latest:  ‘10-K’ on 2/22/24 for 12/31/23

Find Words in Filings emoji
 
  in    Show  and   Hints

  As Of                Filer                Filing    For·On·As Docs:Size

 2/27/04  Mdu Resources Group Inc           10-K       12/31/03   17:549K

Annual Report   —   Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Mdu Resources Group, Inc. 2003 10-K                  154±   680K 
 2: EX-4.E      Certificate of Adjustment to Purchase Price &          1     11K 
                          Redemption Price                                       
 3: EX-10.A     Executive Incentive Compensation Plan                 11±    41K 
 9: EX-10.AA    Bauerly Brothers, Inc. Deferred Compensation Plan      9±    37K 
10: EX-10.AB    Oregon Electric Construction, Inc. Deferred            8±    37K 
                          Compensation Plan                                      
 4: EX-10.V     Agreement on Retirement                                6±    34K 
 5: EX-10.W     Wagner-Smith Company Deferred Compensation Plan        8±    34K 
 6: EX-10.X     Wagner-Smith Equipment Co. Deferred Compensation       8±    34K 
                          Plan                                                   
 7: EX-10.Y     Capital Electric Construction Company, Inc.            8±    34K 
                          Compensation Plan                                      
 8: EX-10.Z     Capital Electric Line Builders, Inc. Deferred          8±    35K 
                          Compensation Plan                                      
11: EX-12       Computation of Ratio of Earnings                       2±    11K 
12: EX-21       List of Subsidiaries                                   2±    13K 
13: EX-23.A     Independent Auditors' Consent                          1     12K 
14: EX-23.B     Notice Regarding Consent of Arthur Andersen LLP        1     11K 
15: EX-31.A     Section 302 Certification of CEO                       2±    12K 
16: EX-31.B     Section 302 Certification of CFO                       2±    12K 
17: EX-32       Section 906 Certifications                             1      9K 


10-K   —   Mdu Resources Group, Inc. 2003 10-K
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
"Item 3 -- . Legal Proceedings
"Item 4 -- . Submission of Matters to a Vote of Security Holders
"Item 5 -- . Market for the Registrant's Common Stock and Related Stockholder Matters
"Item 6 -- . Selected Financial Data
"Item 7 -- . Management's Discussion and Analysis of Financial Condition and Results of Operations
"Item 7A -- . Quantitative and Qualitative Disclosures About Market Risk
"Item 8 -- . Financial Statements and Supplementary Data
"Item 9 -- . Change in and Disagreements with Accountants on Accounting and Financial Disclosure
"Item 9A -- . Controls and Procedures
"Item 10 -- . Directors and Executive Officers of the Registrant
"Item 11. Executive Compensation
"Item 12 -- . Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
"Item 13 -- . Certain Relationships and Related Transactions
"Item 14 -- . Principal Accountant Fees and Services
"Item 15 -- . Exhibits, Financial Statement Schedules and Reports on Form 8-K
"Items 1 and 2. Business and Properties
"Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure


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, 2003 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______________ to ____________ Commission file number 1-3480 MDU Resources Group, Inc. (Exact name of registrant as specified in its charter) Delaware 41-0423660 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) Schuchart Building 918 East Divide Avenue P.O. Box 5650 Bismarck, North Dakota 58506-5650 (Address of principal executive offices) (Zip Code) (701) 222-7900 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange Common Stock, par value $1.00 on which registered and Preference Share Purchase Rights New York Stock Exchange Pacific Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Preferred Stock, par value $100 (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes X. No __. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X Indicate by check mark whether the registrant is an accelerated filer. Yes X. No __. State the aggregate market value of the voting stock held by nonaffiliates of the registrant as of June 30, 2003: $2,486,289,000. Indicate the number of shares outstanding of each of the Registrant's classes of common stock, as of February 20, 2004: 116,749,774 shares. DOCUMENTS INCORPORATED BY REFERENCE. Portions of the Registrant's Proxy Statement, dated March 5, 2004 are incorporated by reference in Part III, Items 10, 11, 12 and 14 of this Report. CONTENTS PART I Items 1 and 2 -- Business and Properties General Electric Natural Gas Distribution Utility Services Pipeline and Energy Services Natural Gas and Oil Production Construction Materials and Mining -- Construction Materials Coal Consolidated Construction Materials and Mining Independent Power Production and Other Item 3 -- Legal Proceedings Item 4 -- Submission of Matters to a Vote of Security Holders PART II Item 5 -- Market for the Registrant's Common Stock and Related Stockholder Matters Item 6 -- Selected Financial Data Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations Item 7A -- Quantitative and Qualitative Disclosures About Market Risk Item 8 -- Financial Statements and Supplementary Data Item 9 -- Change in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A -- Controls and Procedures 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 and Related Stockholder Matters Item 13 -- Certain Relationships and Related Transactions Item 14 -- Principal Accountant Fees and Services PART IV Item 15 -- Exhibits, Financial Statement Schedules and Reports on Form 8-K Signatures Exhibits PART I This Form 10-K contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are all statements other than statements of historical fact, including without limitation, those statements that are identified by the words "anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions. In addition to the risk factors and cautionary statements included in this Form 10-K at Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors and Cautionary Statements that May Affect Future Results, the following are some other factors that should be considered for a better understanding of the financial condition of MDU Resources Group, Inc. (Company). These other factors may impact the Company's financial results in future periods. - Acquisition and disposal of assets or facilities - Changes in operation, performance and construction of plant facilities or other assets - Changes in present or prospective generation - Changes in anticipated tourism levels - The availability of economic expansion or development opportunities - Population growth rates and demographic patterns - Market demand for energy - Changes in tax rates or policies - Unanticipated project delays or changes in project costs - Unanticipated changes in operating expenses or capital expenditures - Labor negotiations or disputes - Inflation rates - Inability of the various contract counterparties to meet their contractual obligations - Changes in accounting principles and/or the application of such principles to the Company - Changes in technology - Changes in legal proceedings - The ability to effectively integrate the operations of acquired companies - Fluctuations in natural gas and crude oil prices - Decline in general economic environment - Changes in governmental regulation - Changes in currency exchange rates - Unanticipated increases in competition - Variations in weather ITEMS 1 AND 2. BUSINESS AND PROPERTIES GENERAL The 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 the Schuchart Building, 918 East Divide Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 222-7900. Montana-Dakota Utilities Co. (Montana-Dakota), a public utility division of the Company, through the electric and natural gas distribution segments, generates, transmits and distributes electricity and distributes natural gas in the northern Great Plains. Great Plains Natural Gas Co. (Great Plains), another public utility division of the Company, distributes natural gas in southeastern North Dakota and western Minnesota. These operations also supply related value-added products and services in the northern Great Plains. The Company, through its wholly owned subsidiary, Centennial Energy Holdings, Inc. (Centennial), owns WBI Holdings, Inc. (WBI Holdings), Knife River Corporation (Knife River), Utility Services, Inc. (Utility Services), Centennial Energy Resources LLC (Centennial Resources) and Centennial Holdings Capital LLC (Centennial Capital). WBI Holdings is comprised of the pipeline and energy services and the natural gas and oil production segments. The pipeline and energy services segment provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems primarily in the Rocky Mountain and northern Great Plains regions of the United States. The pipeline and energy services segment also provides energy-related management services, including cable and pipeline magnetization and locating. The natural gas and oil production segment is engaged in natural gas and oil acquisition, exploration and production activities, primarily in the Rocky Mountain region of the United States and in and around the Gulf of Mexico. Knife River mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ready-mixed concrete, cement, asphalt and other value-added products, as well as performs integrated construction services, in the central and western United States and in the states of Alaska and Hawaii. Utility Services specializes in electrical line construction, pipeline construction, inside electrical wiring and cabling and the manufacture and distribution of specialty equipment. Centennial Resources owns electric generating facilities in the United States and has an investment in an electric generating facility in Brazil. Electric capacity and energy produced at these facilities are primarily sold under long-term contracts to nonaffiliated entities. Centennial Resources includes investments in potential new growth opportunities that are not directly being pursued by the other business units, as well as projects outside the United States which are consistent with the Company's philosophy, growth strategy and areas of expertise. These activities are reflected in independent power production and other. Centennial Capital insures various types of risks as a captive insurer for certain of the Company's subsidiaries. The function of the captive is to fund the deductible layers of the insured companies' general liability and automobile liability coverages. Centennial Capital also owns certain real and personal property and contract rights. These activities are reflected in independent power production and other. As of December 31, 2003, the Company had 7,797 full-time employees with 100 employed at MDU Resources Group, Inc., 913 at Montana-Dakota, 59 at Great Plains, 457 at WBI Holdings, 3,590 at Knife River's operations, 2,665 at Utility Services and 13 at Centennial Resources. The number of employees at certain Company operations fluctuates during the year depending upon the number and size of construction projects. The Company considers its relations with employees to be satisfactory. At Montana-Dakota and Williston Basin Interstate Pipeline Company (Williston Basin), an indirect wholly owned subsidiary of WBI Holdings, 436 and 70 employees, respectively, are represented by the International Brotherhood of Electrical Workers (IBEW). Labor contracts with such employees are in effect through April 30, 2007 and March 31, 2005, for Montana-Dakota and Williston Basin, respectively. Knife River has 40 labor contracts that represent 730 of its construction materials employees. Knife River is currently in negotiations on four of its labor contracts. Utility Services has 60 labor contracts representing the majority of its employees. The majority of the labor contracts contain provisions that prohibit work stoppages or strikes and provide for binding arbitration dispute resolution in the event of an extended disagreement. The Company's principal properties, which are of varying ages and are of different construction types, are believed to be generally in good condition, are well maintained, and are generally suitable and adequate for the purposes for which they are used. The financial results and data applicable to each of the Company's business segments as well as their financing requirements are set forth in Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations and Item 8 -- Financial Statements and Supplementary Data - Note 14 and Supplementary Financial Information. The Company has formed an alliance with several electric cooperatives in the region to evaluate potential utility opportunities presented by the bankruptcy of NorthWestern Corporation (NorthWestern). NorthWestern filed for Chapter 11 bankruptcy protection on September 14, 2003. The operations of the Company and certain of its subsidiaries are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations and state hazard communication standards. The Company believes that it is in substantial compliance with these regulations, except as what may be ultimately determined with regard to the Portland, Oregon Harbor Superfund Site, which is discussed under Items 1 and 2 -- Business and Properties - Consolidated Construction Materials and Mining - Environmental Matters and in Item 8 -- Financial Statements and Supplementary Data - Note 19. There are no pending Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) actions for any of the Company's properties, other than the Portland, Oregon Harbor Superfund Site. Governmental regulations establishing environmental protection standards are continuously evolving and, therefore, the character, scope, cost and availability of the measures that will permit compliance with these laws or regulations cannot be accurately predicted. Disclosure regarding specific environmental matters applicable to each of the Company's businesses is set forth under each business description below. This annual report on Form 10-K, the Company's quarterly reports on Form 10-Q, the Company's current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available through the Company's website as soon as reasonably practicable after the Company has filed such reports with the Securities and Exchange Commission (SEC). The Company's website address is www.mdu.com. The information available on the Company's website is not part of this annual report on Form 10-K. ELECTRIC General -- Montana-Dakota provides electric service at retail, serving over 117,000 residential, commercial, industrial and municipal customers located in 177 communities and adjacent rural areas as of December 31, 2003. The principal properties owned by Montana- Dakota for use in its electric operations include interests in seven electric generating stations, as further described under System Supply and System Demand, and approximately 3,100 and 4,200 miles of transmission and distribution lines, respectively. Montana-Dakota has obtained and holds valid and existing franchises authorizing it to conduct its electric operations in all of the municipalities it serves where such franchises are required. For additional information regarding Montana-Dakota's franchises, see Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations - Electric. As of December 31, 2003, Montana-Dakota's net electric plant investment approximated $296.5 million. All of Montana-Dakota's electric properties, with certain exceptions, are subject to the lien of the Indenture of Mortgage dated May 1, 1939, as supplemented, amended and restated, from the Company to The Bank of New York and Douglas J. MacInnes, successor trustees, and are subject to the junior lien of the Indenture dated as of December 15, 2003, as supplemented, from the Company to The Bank of New York, as trustee. The electric operations of Montana-Dakota are subject to regulation by the Federal Energy Regulatory Commission (FERC) under provisions of the Federal Power Act with respect to the transmission and sale of power at wholesale in interstate commerce, interconnections with other utilities, the issuance of securities, accounting and other matters. Retail rates, service, accounting and, in certain instances, security issuances are also subject to regulation by the North Dakota Public Service Commission (NDPSC), Montana Public Service Commission (MTPSC), South Dakota Public Utilities Commission (SDPUC) and Wyoming Public Service Commission (WYPSC). The percentage of Montana-Dakota's 2003 electric utility operating revenues by jurisdiction is as follows: North Dakota -- 59 percent; Montana - - 24 percent; South Dakota -- 7 percent and Wyoming -- 10 percent. System Supply and System Demand -- Through an interconnected electric system, Montana-Dakota serves markets in portions of the following states and major communities -- western North Dakota, including Bismarck, Dickinson and Williston; eastern Montana, including Glendive and Miles City; and northern South Dakota, including Mobridge. The interconnected system consists of seven on-line electric generating stations which have an aggregate turbine nameplate rating attributable to Montana-Dakota's interest of 434,230 kilowatts (kW) and a total summer net capability of 473,460 kW. Montana-Dakota's four principal generating stations are steam- turbine generating units using coal for fuel. The nameplate rating for Montana-Dakota's ownership interest in these four stations (including interests in the Big Stone Station and the Coyote Station aggregating 22.7 percent and 25.0 percent, respectively) is 327,758 kW. Three combustion turbine peaking stations supply the balance of Montana-Dakota's interconnected system electric generating capability. A 40-megawatt natural gas- fueled combustion turbine was added near Glendive, Montana and became operational in late May 2003. Additionally, Montana- Dakota has contracted to purchase through October 31, 2006, 66,400 kW of participation power annually from Basin Electric Power Cooperative for its interconnected system. Montana-Dakota also has an agreement through December 31, 2020 with the Western Area Power Administration (WAPA) to provide federal hydroelectric power to eligible Native American customers on the Fort Peck Indian Reservation. The program provides a credit to the customers for the portion of their power received from the federal hydroelectric system. The associated summer monthly capability from the WAPA agreement is 2,819 kW. In August 2002, Montana-Dakota entered into an agreement with Dakota I Power Partners to purchase energy from a 20-megawatt wind energy farm to be constructed in Dickey County, North Dakota. The contract provides for the wind farm to be on-line early to mid-2004. Regulatory approvals have been obtained from the NDPSC and SDPUC for the purchase of energy from the wind farm, but Dakota I Power Partners has not yet begun construction. Montana-Dakota cannot predict whether, or when, construction of the project will be commenced or completed. On January 9, 2004, Montana-Dakota entered into a firm capacity contract with a Midwest utility to purchase 5 megawatts of capacity during the period May 1, 2004 to October 31, 2004, 15 megawatts during the period May 1, 2005 to October 31, 2005 and 25 megawatts during the period May 1, 2006 to October 31, 2006. In addition, on January 9, 2004, Montana-Dakota entered into a firm power contract with the Midwest utility to purchase 70 megawatts of power during the period November 1, 2006 to December 31, 2006, 80 megawatts during the period January 1, 2007 to December 31, 2007, 90 megawatts during the period January 1, 2008 to December 31, 2008 and 100 megawatts during the period January 1, 2009 to December 31, 2010. All capacity and power purchases from these contracts are contingent upon the parties securing transmission service for the delivery of capacity and power to Montana-Dakota's customer load. The following table sets forth details applicable to the Company's electric generating stations: 2003 Net Generation Nameplate Summer (kilowatt- Generating Rating Capability hours in Station Type (kW) (kW) thousands) North Dakota -- Coyote* Steam 103,647 106,750 703,106 Heskett Steam 86,000 104,050 605,187 Williston Combustion Turbine 7,800 9,600 (79)** South Dakota -- Big Stone* Steam 94,111 103,660 734,902 Montana -- Lewis & Clark Steam 44,000 52,300 323,167 Glendive Combustion Turbine 75,522 72,800 16,349 Miles City Combustion Turbine 23,150 24,300 2,252 434,230 473,460 2,384,884 _________________________________ * Reflects Montana-Dakota's ownership interest. ** Station use, to meet Mid-Continent Area Power Pool's (MAPP) accreditation requirements, exceeded generation. Virtually all of the current fuel requirements of the Coyote, Heskett and Lewis & Clark stations are met with coal supplied by subsidiaries of Westmoreland Coal Company (Westmoreland). Contracts with Westmoreland for the Coyote, Heskett and Lewis & Clark stations expire in May 2016, December 2005, and December 2007, respectively. The majority of the Big Stone Station's fuel requirements are currently being met with coal supplied by RAG Coal West, Inc. under a contract that expires on December 31, 2004. The RAG Coal West, Inc. coal supply arrangement allows for the purchase during 2004 of 1.5 million tons of coal from the Belle Ayr mine and 500,000 tons of coal from the Eagle Butte mine, at contracted pricing. The Coyote coal supply agreement provides for the purchase of coal necessary to supply all the coal requirements of the Coyote Station or 30,000 tons per week, whichever may be the greater quantity at contracted pricing. The maximum quantity of coal during the term of the agreement, and any extension, is 75 million tons. The Heskett coal supply agreement allows for the purchase at contracted pricing. The anticipated fuel supply requirement for 2004 is 375,000 tons. The Lewis & Clark coal supply agreement provides for the purchase of coal necessary to supply all the coal requirements of the Lewis & Clark Station, at contracted pricing. Montana-Dakota estimates the coal requirement to be in the range of 250,000 to 325,000 tons per contract year. During the years ended December 31, 1999, through December 31, 2003, the average cost of coal purchased, including freight, per million British thermal units (Btu) at Montana-Dakota's electric generating stations (including the Big Stone and Coyote stations) in the interconnected system and the average cost per ton, including freight, of the coal purchased was as follows: Years Ended December 31, 2003 2002 2001 2000 1999 Average cost of coal per million Btu $ 1.04 $ .98 $ .92 $ .94 $ .90 Average cost of coal per ton $15.22 $14.39 $13.43 $13.68 $13.31 The maximum electric peak demand experienced to date attributable to sales to retail customers on the interconnected system was 470,000 kW in August 2003. 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 2009 will approximate 0.9 percent annually. Montana-Dakota's latest forecast indicates that its kilowatt-hour (kWh) sales growth rate, on a normalized basis, through 2009 will approximate 1.1 percent annually. Montana-Dakota currently estimates that it has adequate capacity available through existing baseload generating stations, turbine peaking stations and long-term firm purchase contracts to meet the peak demand requirements of its customers until the year 2007. Additional capacity that is needed in 2007 or after to replace expiring contracts and meet system growth requirements is expected to be met through power contracts or building or acquiring an additional 175 megawatts to 200 megawatts of capacity. Montana-Dakota is working with the state of North Dakota to determine the feasibility of constructing a lignite- fired power plant in western North Dakota. Montana-Dakota is also involved in a coalition with four other utilities to study the feasibility of building a coal-based facility possibly combined with a wind energy facility at potential sites in North Dakota, South Dakota and Iowa. The costs of building and/or acquiring the additional generating capacity are expected to be recovered in rates. Montana-Dakota has major interconnections with its neighboring utilities, all of which are MAPP members. Montana-Dakota considers these interconnections adequate for coordinated planning, emergency assistance, exchange of capacity and energy and power supply reliability. Through a separate electric system (Sheridan System), Montana- Dakota serves Sheridan, Wyoming and neighboring communities. The maximum peak demand experienced to date and attributable to Montana-Dakota sales to retail consumers on that system was approximately 52,300 kW and occurred in August 2003. The Sheridan System is supplied through an interconnection with Black Hills Power and Light Company under a power supply contract through December 31, 2006 that allows for the purchase of up to 55,000 kW of capacity annually. Regulation and Competition -- Montana-Dakota is subject to competition in varying degrees, in certain areas, from rural electric cooperatives, on-site generators, co-generators and municipally owned systems. In addition, competition in varying degrees exists between electricity and alternative forms of energy such as natural gas. The restructuring of the electric industry has been slowed due to certain events in the industry. In addition, as a result of competition in electric generation, wholesale power markets have become increasingly competitive and evaluations are ongoing concerning retail competition. Montana-Dakota is a member of the Midwest Independent Transmission System Operator, Inc. (Midwest ISO). The Midwest ISO is responsible for operational control of the transmission systems of its members. The Midwest ISO agreement permits Montana-Dakota to be a separate pricing zone. The Midwest ISO also provides security center operations and tariff administration. The Montana legislature passed an electric industry restructuring bill, effective May 2, 1997. The bill provided for full customer choice of electric supplier by July 1, 2002, stranded cost recovery and other provisions. Based on the provisions of such restructuring bill, because Montana-Dakota operates in more than one state, the Company had the option of deferring its transition to full customer choice until 2006. In March 2001, legislation was passed in Montana which delays the restructuring and transition to full customer choice until a time when Montana-Dakota can reasonably implement customer choice in the state of its primary service territory. In its 1997 legislative session, the North Dakota legislature established an Electric Industry Competition Committee to study over a six-year period the impact of competition on the generation, transmission and distribution of electric energy in North Dakota. In 2003, the committee was expanded and the study was extended for an additional four years. To date, the Committee has made no recommendation regarding restructuring. In 1997, the WYPSC selected a consultant to perform a study on the impact of electric restructuring in Wyoming. The study found no material economic benefits. No further action is pending at this time. The SDPUC has not initiated any proceedings to date concerning retail competition or electric industry restructuring. Federal legislation addressing this issue continues to be discussed. Although Montana-Dakota is unable to predict the outcome of such regulatory proceedings or legislation, or the extent to which retail competition may occur, Montana-Dakota is continuing to take steps to effectively operate in an increasingly competitive environment. For additional information regarding retail competition, see Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations - Prospective Information - Electric. On May 30, 2003, Montana-Dakota filed an application with the NDPSC for an electric rate increase. Montana-Dakota requested a total of $7.8 million annually or 9.1 percent above current rates. On July 23, 2003, Montana-Dakota and the NDPSC Staff filed a Settlement Agreement with the NDPSC agreeing on the issues of rate of return, capital structure and cost of capital components. On October 22, 2003, the NDPSC approved the Settlement Agreement. On November 19, 2003, Montana-Dakota and the NDPSC Staff filed an additional Settlement Agreement to resolve all remaining outstanding issues with the NDPSC. This Settlement Agreement reflected an increase of $1.0 million annually and a sharing mechanism between Montana-Dakota and retail customers of wholesale electric sales margins. On December 18, 2003, the NDPSC approved the November 2003 Settlement Agreement and required Montana-Dakota to file a compliance filing with the NDPSC. On January 14, 2004, the NDPSC approved Montana-Dakota's compliance filing, which was filed on January 7, 2004, with rates effective with service rendered on and after January 23, 2004. Fuel adjustment clauses contained in North Dakota and South Dakota jurisdictional electric rate schedules allow Montana-Dakota to reflect increases or decreases in fuel and purchased power costs (excluding demand charges) on a timely basis. Expedited rate filing procedures in Wyoming allow Montana- Dakota to timely reflect increases or decreases in fuel and purchased power costs. In Montana (24 percent of electric revenues) such cost changes are includible in general rate filings. Environmental Matters -- Montana-Dakota's electric operations are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations and state hazard communication standards. Montana-Dakota believes it is in substantial compliance with these regulations. The U.S. Environmental Protection Agency (EPA) may authorize a state to manage federal programs such as the Federal Clean Air Act (Clean Air Act) and Federal Clean Water Act (Clean Water Act), under approved state programs. This is the case in all the states where Montana-Dakota operates. Montana-Dakota's electric generation facilities have Title V Operating Permits, under the Clean Air Act, issued by the states in which it operates. These permits have a five-year life, with the first of these permits expiring on October 15, 2004. Montana- Dakota renews these permits as necessary prior to expiration. State water discharge permits issued under the requirements of the Clean Water Act are maintained for power production facilities located on the Yellowstone and Missouri Rivers. These permits also have a five-year life, with the first permit expiring on November 30, 2005. Montana-Dakota renews these permits as necessary prior to expiration. Other permits held by these facilities may include an initial siting permit, which is typically a one-time, preconstruction permit issued by the state; state permits to dispose of combustion by-products; state authorizations to withdraw water for operations; and U.S. Army Corps of Engineers (Army Corps) permits to construct water intake structures. Montana-Dakota's Army Corps permits grant one-time permission to construct, and do not require renewal. Other permit terms vary, and the permits are renewed as necessary. Montana-Dakota's electric operations are conditionally-exempt small quantity hazardous waste generators and subject only to minimum regulation under the Resource Conservation and Recovery Act (RCRA). Montana-Dakota routinely handles polychlorinated biphenyls (PCBs) from their electric operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required. Montana-Dakota did not incur any material environmental expenditures in 2003 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2006. For matters involving Montana-Dakota and the North Dakota Department of Health and a related matter involving the Dakota Resource Council, see Item 3 -- Legal Proceedings. NATURAL GAS DISTRIBUTION General -- Montana-Dakota sells natural gas at retail, serving over 220,000 residential, commercial and industrial customers located in 142 communities and adjacent rural areas as of December 31, 2003, and provides natural gas transportation services to certain customers on its system. Great Plains sells natural gas at retail, serving over 22,000 residential, commercial and industrial customers located in 19 communities and adjacent rural areas as of December 31, 2003, and provides natural gas transportation services to certain customers on its system. These services for the two public utility divisions are provided through distribution systems aggregating over 5,100 miles. Montana-Dakota and Great Plains have obtained and hold valid and existing franchises authorizing them to conduct natural gas distribution operations in all of the municipalities they serve where such franchises are required. For additional information regarding Montana-Dakota's and Great Plains' franchises, see Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations - Prospective Information - Natural gas distribution. As of December 31, 2003, Montana-Dakota's and Great Plains' net natural gas distribution plant investment approximated $147.1 million. All of Montana-Dakota's natural gas distribution properties, with certain exceptions, are subject to the lien of the Indenture of Mortgage dated May 1, 1939, as supplemented, amended and restated, from the Company to The Bank of New York and Douglas J. MacInnes, successor trustees, and are subject to the junior lien of the Indenture dated as of December 15, 2003, as supplemented, from the Company to The Bank of New York, as trustee. The natural gas distribution operations of Montana-Dakota are subject to regulation by the NDPSC, MTPSC, SDPUC and WYPSC regarding retail rates, service, accounting and, in certain instances, security issuances. The natural gas distribution operations of Great Plains are subject to regulation by the NDPSC and Minnesota Public Utilities Commission (MPUC) regarding retail rates, service, accounting and, in certain instances, security issuances. The percentage of Montana-Dakota's and Great Plains' 2003 natural gas utility operating revenues by jurisdiction is as follows: North Dakota -- 39 percent; Minnesota -- 12 percent; Montana -- 25 percent; South Dakota -- 18 percent and Wyoming -- 6 percent. System Supply, System Demand and Competition -- Montana-Dakota and Great Plains serve retail natural gas markets, consisting principally of residential and firm commercial space and water heating users, in portions of the following states and major communities -- North Dakota, including Bismarck, Dickinson, Wahpeton, Williston, Minot and Jamestown; western Minnesota, including Fergus Falls, Marshall and Crookston; eastern Montana, including Billings, Glendive and Miles City; western and north-central South Dakota, including Rapid City, Pierre and Mobridge; and northern Wyoming, including Sheridan. These markets are highly seasonal and sales volumes depend on the weather. The following table reflects this segment's natural gas sales, natural gas transportation volumes and degree days as a percentage of normal during the last five years: Years Ended December 31, 2003* 2002* 2001* 2000** 1999 Mdk (thousands of decatherms) Sales: Residential 21,498 21,893 20,087 20,554 18,059 Commercial 15,537 16,044 14,661 14,590 12,030 Industrial 1,537 1,621 1,731 1,451 842 Total 38,572 39,558 36,479 36,595 30,931 Transportation: Commercial 1,528 1,849 1,847 2,067 1,975 Industrial 12,375 11,872 12,491 12,247 9,576 Total 13,903 13,721 14,338 14,314 11,551 Total Throughput 52,475 53,279 50,817 50,909 42,482 Degree days *** (% of normal) 97.3% 101.1% 94.5% 100.4% 88.8% _________________________________ * Includes Great Plains ** Sales and transportation volumes for Great Plains are for the period July through December 2000. Degree days exclude Great Plains. ***Degree days are a measure of daily temperature-related demand for energy for heating. Competition in varying degrees exists between natural gas and other fuels and forms of energy. Montana-Dakota and Great Plains have established various natural gas transportation service rates for their distribution businesses to retain interruptible commercial and industrial load. Certain of these services include transportation under flexible rate schedules whereby Montana-Dakota's and Great Plains' interruptible customers can avail themselves of the advantages of open access transportation on regional transmission pipelines, including the system of Williston Basin, Northern Natural Gas Company and Viking Gas Transmission Company. These services have enhanced Montana- Dakota's and Great Plains' competitive posture with alternate fuels, although certain of Montana-Dakota's customers have bypassed the respective distribution systems by directly accessing transmission pipelines located within close proximity. These bypasses did not have a material effect on results of operations. Montana-Dakota and Great Plains acquire their system requirements directly from producers, processors and marketers. Such natural gas is supplied by a portfolio of contracts specifying market-based pricing, and is transported under transportation agreements by Williston Basin, Kinder Morgan, Inc., South Dakota Intrastate Pipeline Company, Northern Border Pipeline Company, Viking Gas Transmission Company and Northern Natural Gas Company to provide firm service to their customers. Montana-Dakota has also contracted with Williston Basin to provide firm storage services that enable Montana-Dakota to meet winter peak requirements as well as allow it to better manage its natural gas costs by purchasing natural gas at more uniform daily volumes throughout the year. Demand for natural gas, which is a widely traded commodity, is sensitive to seasonal heating and industrial load requirements as well as changes in market price. Montana-Dakota and Great Plains believe that, based on regional supplies of natural gas and the pipeline transmission network currently available through its suppliers and pipeline service providers, supplies are adequate to meet its system natural gas requirements for the next five years. Regulatory Matters -- In December 2002, Montana-Dakota filed an application with the SDPUC for a natural gas rate increase. Montana-Dakota requested a total of $2.2 million annually or 5.8 percent above current rates. On October 27, 2003, Montana-Dakota and the SDPUC Staff filed a Settlement Stipulation with the SDPUC agreeing to an increase of $1.3 million annually. On December 2, 2003, the SDPUC approved the Settlement Stipulation effective with service rendered on and after December 2, 2003. In October 2002, Great Plains filed an application with the MPUC for a natural gas rate increase. Great Plains requested a total of $1.6 million annually or 6.9 percent above current rates. In December 2002, the MPUC issued an Order setting interim rates that approved an interim increase of $1.4 million annually effective December 6, 2002. Great Plains began collecting such rates effective December 6, 2002, subject to refund until the MPUC issues a final order. On October 9, 2003, the MPUC issued a Final Order authorizing an increase of $1.1 million annually and requiring Great Plains to file a compliance filing with the MPUC. On January 16, 2004, the MPUC issued an Order accepting Great Plains' compliance filing, which was filed on November 10, 2003, effective with service rendered on and after January 16, 2004. Reserves have been provided for a portion of the revenues that have been collected subject to refund for certain of the above proceedings. The Company believes that such reserves are adequate based on its assessment of the ultimate outcome of the proceedings. Montana-Dakota's and Great Plains' retail natural gas rate schedules contain clauses permitting monthly adjustments in rates based upon changes in natural gas commodity, transportation and storage costs. Current regulatory practices allow Montana-Dakota and Great Plains to recover increases or refund decreases in such costs within a period ranging from 24 months to 28 months from the time such costs are paid. Environmental Matters -- Montana-Dakota's and Great Plains' natural gas distribution operations are subject to federal, state and local environmental, facility siting, zoning and planning laws and regulations. Montana-Dakota and Great Plains believe they are in substantial compliance with those regulations. Montana-Dakota's and Great Plains' operations are conditionally-exempt small quantity hazardous waste generators and subject only to minimum regulation under the RCRA. Montana- Dakota and Great Plains routinely handle PCBs from their natural gas operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required. Montana-Dakota and Great Plains did not incur any material environmental expenditures in 2003 and do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2006. UTILITY SERVICES General -- Utility Services specializes in electrical line construction, pipeline construction, inside electrical wiring and cabling and the manufacture and distribution of specialty equipment. These services are provided to utilities and large manufacturing, commercial, government and institutional customers. Construction and maintenance crews are active year round. However, activity in certain locations may be seasonal in nature due to the effects of weather. Utility Services operates a fleet of owned and leased trucks and trailers, support vehicles and specialty construction equipment, such as backhoes, excavators, trenchers, generators, boring machines and cranes. In addition, as of December 31, 2003, Utility Services owned or leased offices in 13 states. This space is used for offices, equipment yards, warehousing, storage and vehicle shops. At December 31, 2003, Utility Services' net plant investment was approximately $46.6 million. The utility services segment backlog is comprised of the uncompleted portion of services to be performed under job- specific contracts and the estimated value of future services that it expects to provide under other master agreements. The backlog at January 31, 2004, was approximately $142 million compared to approximately $152 million at January 31, 2003. The Company expects to complete a significant amount of the backlog during the year ending December 31, 2004. Due to the nature of its contractual arrangements, in many instances the Company's customers are not committed to the specific volumes of services to be purchased under a contract, but rather the Company is committed to perform these services if and to the extent requested by the customer. The customer is, however, obligated to obtain these services from the Company if they are not performed by the customer's employees. Therefore, there can be no assurance as to the customer's requirements during a particular period or that such estimates at any point in time are predictive of future revenues. This industry is experiencing a shortage of linemen in certain areas. Utility Services works with the National Electrical Contractors Association and the IBEW on hiring and recruiting of qualified linemen. Competition -- Utility Services operates in a highly competitive business environment. Most of Utility Services' work is obtained on the basis of competitive bids or by negotiation of either cost plus or fixed price contracts. The workforce and equipment are highly mobile, providing greater flexibility in the size and location of Utility Services' market area. Competition is based primarily on price and reputation for quality, safety and reliability. The size and area location of the services provided as well as the state of the economy will be factors in the number of competitors that Utility Services will encounter on any particular project. Utility Services believes that the diversification of the services it provides, the market it serves throughout the United States and the management of its workforce will enable it to effectively operate in this competitive environment. Utilities and independent contractors represent the largest customer base for this segment. Accordingly, utility and sub- contract work accounts for a significant portion of the work performed by the utility services segment and the amount of construction contracts is dependent to a certain extent on the level and timing of maintenance and construction programs undertaken by customers. Utility Services relies on repeat customers and strives to maintain successful long-term relationships with these customers. Environmental Matters -- Utility Services' operations are subject to regulation customary for the industry, including federal, state and local environmental compliance. Utility Services believes it is in substantial compliance with these regulations. The nature of Utility Services' operations is such that few, if any, environmental permits are required. Operational convenience supports the use of petroleum storage tanks in several locations, which are permitted under state programs authorized by the EPA. Utility Services currently has no ongoing remediation related to releases from petroleum storage tanks. Utility Services operations are conditionally-exempt small quantity waste generators, subject to minimal regulation under the RCRA. Federal permits for specific construction and maintenance jobs that may require these permits are typically obtained by the hiring entity, and not by Utility Services. Utility Services did not incur any material environmental expenditures in 2003 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2006. PIPELINE AND ENERGY SERVICES General -- Williston Basin, the principal regulated business of WBI Holdings, owns and operates over 3,700 miles of transmission, gathering and storage lines and owns or leases and operates 26 compressor stations located in the states of Montana, North Dakota, South Dakota and Wyoming. Included in the transmission lines described above are 253 miles of 16-inch natural gas pipeline built in 2003 that spans sections of Wyoming, Montana, and North Dakota. This newly constructed pipeline began transporting natural gas from developing coalbed and conventional natural gas production facilities in central Wyoming and south central Montana to interconnecting pipelines on December 23, 2003. Three underground storage fields located in Montana and Wyoming provide storage services to local distribution companies, producers, natural gas marketers and others, and serve to enhance system deliverability. Williston Basin's system is strategically located near five natural gas producing basins, making natural gas supplies available to Williston Basin's transportation and storage customers. The system has 11 interconnecting points with other pipeline facilities allowing for the receipt and/or delivery of natural gas to and from other regions of the country. At December 31, 2003, Williston Basin's net plant investment was approximately $202.1 million. WBI Holdings, through its nonregulated pipeline businesses, owns and operates gathering facilities in Colorado, Kansas, Montana and Wyoming. These facilities include approximately 1,600 miles of field gathering lines and 77 owned or leased compression facilities, some of which interconnect with Williston Basin's system. A one-sixth interest in the assets of various offshore gathering pipelines and associated onshore pipeline and related processing facilities are also owned by WBI Holdings. In addition, WBI Holdings provides installation sales and/or leasing of alternate energy delivery systems, primarily propane air plants, as well as providing energy efficiency product sales and installation services to large end users. WBI Holdings, through its energy services businesses, provides natural gas purchase and sales services to local distribution companies, other marketers and a limited number of large end users, primarily using natural gas produced by the Company's natural gas and oil production segment. Certain of the services are provided based on contracts that call for a determinable quantity of natural gas. Energy services currently estimates that it can adequately meet the requirements of these contracts. Energy services transacts a significant portion of its business in the Northern Plains and Rocky Mountain regions of the United States. In 2001, the company sold the vast majority of its energy marketing operations. Energy services also owns Innovatum, Inc. (Innovatum), a cable and pipeline magnetization and locating company. Innovatum provides products and services that assist the oil and gas and telecommunication industries with accurate location and tracking of submerged pipelines and cables. Additionally, Innovatum manufactures and resells a line of terrestrial, hand-held locators that are used for locating and identifying underground metal objects, utility systems and water distribution system leaks. Innovatum recently developed a hand-held locating device that can detect both magnetic and plastic materials. One of the possible uses for this product would be in the detection of unexploded ordnance. Innovatum is in the preliminary stages of working with and demonstrating the device to a Department of Defense contractor and has met with individuals from the Department of Defense. For additional information regarding these operations, see Item 7 -- Management's Discussion and Analysis of Financial Conditions and Results of Operations - Risk Factors and Cautionary Statements that May Affect Future Results - Economic Risks. Under the Natural Gas Act, as amended, Williston Basin is subject to the jurisdiction of the FERC regarding certificate, rate, service and accounting matters. System Demand and Competition -- Williston Basin competes with several pipelines for its customers' transportation business and at times may discount rates in an effort to retain market share. However, the strategic location of Williston Basin's system near five natural gas producing basins and the availability of underground storage and gathering services provided by Williston Basin and affiliates along with interconnections with other pipelines serve to enhance Williston Basin's competitive position. Although a significant portion of Williston Basin's firm customers, which include Montana-Dakota, have relatively secure residential and commercial end-users, virtually all have some price-sensitive end-users that could switch to alternate fuels. Williston Basin transports substantially all of Montana- Dakota's natural gas utilizing firm transportation agreements, which at December 31, 2003, represented 75 percent of Williston Basin's currently subscribed firm transportation capacity. In October 2001, Montana-Dakota executed a firm transportation agreement with Williston Basin for a term of five years expiring in June 2007. In addition, in July 1995, Montana-Dakota entered into a 20-year contract with Williston Basin to provide firm storage services to facilitate meeting Montana-Dakota's winter peak requirements. System Supply -- Williston Basin's underground storage facilities have a certificated storage capacity of approximately 353 billion cubic feet (Bcf), including 193 Bcf of working gas capacity, 85 Bcf of cushion gas and 75 Bcf of native gas. The native gas includes 29 Bcf of recoverable gas. Williston Basin's storage facilities enable its customers to purchase natural gas at more uniform daily volumes throughout the year and, thus, facilitate meeting winter peak requirements. Natural gas supplies from traditional regional sources have declined during the past several years and such declines are anticipated to continue. As a result, Williston Basin anticipates that a potentially significant amount of the future supply needed to meet its customers' demands will come from non- traditional, off-system sources. The Company's coalbed natural gas assets in the Powder River Basin are expected to meet some of these supply needs. For additional information regarding coalbed natural gas legal proceedings, see Item 3 -- Legal Proceedings and Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors and Cautionary Statements that May Affect Future Results - Environmental and Regulatory Risks. Williston Basin expects to facilitate the movement of these supplies by making available its transportation and storage services. Williston Basin will continue to look for opportunities to increase transportation and storage services through system expansion or other pipeline interconnections or enhancements that could provide substantial future benefits. Regulatory Matters and Revenues Subject to Refund -- In December 1999, Williston Basin filed a general natural gas rate change application with the FERC. Williston Basin began collecting such rates effective June 1, 2000, subject to refund. In May 2001, the Administrative Law Judge (ALJ) issued an Initial Decision on Williston Basin's natural gas rate change application. The Initial Decision addressed numerous issues relating to the rate change application, including matters relating to allowable levels of rate base, return on common equity, and cost of service, as well as volumes established for purposes of cost recovery, and cost allocation and rate design. On July 3, 2003, the FERC issued its Order on Initial Decision. The Order on the Initial Decision affirmed the ALJ's Initial Decision on many of the issues including rate base and certain cost of service items as well as volumes to be used for purposes of cost recovery, and cost allocation and rate design. However, there are other issues as to which the FERC differed with the ALJ including return on common equity and the correct level of corporate overhead expense. On August 4, 2003, Williston Basin requested a rehearing of a number of issues including determinations associated with cost of service, throughput, and cost allocation and rate design, as discussed in the FERC's Order on Initial Decision. On September 3, 2003, the FERC issued an Order granting Williston Basin's request for rehearing of the July 3, 2003, Order on Initial Decision. The Company is awaiting a decision from the FERC on the merits of the Company's rehearing request and is unable to predict the timing of the FERC's decision. Reserves have been provided for a portion of the revenues that have been collected subject to refund with respect to Williston Basin's pending regulatory proceeding. Williston Basin believes that such reserves are adequate based on its assessment of the ultimate outcome of the proceeding. Environmental Matters -- WBI Holdings' pipeline and energy services' operations are generally subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations. WBI Holdings believes it is in substantial compliance with those regulations. The ongoing operations of Williston Basin and Bitter Creek Pipelines, LLC (Bitter Creek), an indirect wholly owned subsidiary of WBI Holdings, are subject to the Clean Air Act and the Clean Water Act. Administration of many provisions of these laws has been delegated to the states where Williston Basin and Bitter Creek operate, and permit terms vary. Some permits require annual renewal, some have terms ranging from one to five years and others have no expiration date. Permits are renewed as necessary. Detailed environmental assessments are included in the permitting processes of the FERC for both the construction and abandonment of Williston Basin's natural gas transmission pipelines. WBI Holdings' pipeline and energy services' operations did not incur any material environmental expenditures in 2003 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2006. NATURAL GAS AND OIL PRODUCTION General -- Fidelity Exploration & Production Company (Fidelity), a direct wholly owned subsidiary of WBI Holdings, is involved in the acquisition, exploration, development and production of natural gas and oil resources. Fidelity's activities include the acquisition of producing properties with potential development opportunities, exploratory drilling and the operation and development of natural gas production properties. Fidelity also shares revenues and expenses from the development of specified properties located primarily in the Rocky Mountain region of the United States and in and around the Gulf of Mexico in proportion to its ownership interests. Fidelity owns in fee or holds natural gas leases for the properties it operates in Colorado, Montana, North Dakota and Wyoming. These rights are in the Bonny Field located in eastern Colorado, the Cedar Creek Anticline in southeastern Montana and southwestern North Dakota, the Bowdoin area located in north- central Montana and in the Powder River Basin of Montana and Wyoming. Natural gas production from operated properties was 74 percent of total natural gas production for the year ended December 31, 2003. Fidelity continues to seek additional reserve and production growth opportunities through the direct acquisition of producing properties, acquisition of exploration and development leaseholds and acreage and through exploratory drilling opportunities, as well as development of its existing properties. Future growth is dependent upon its success in these endeavors. Operating Information -- Information on natural gas and oil production, average realized prices and production costs per net equivalent Mcf related to natural gas and oil interests for 2003, 2002 and 2001, are as follows: 2003 2002 2001 Natural Gas: Production (MMcf) 54,727 48,239 40,591 Average realized price (including hedges) $ 3.90 $ 2.72 $ 3.78 Average realized price (excluding hedges) $ 4.28 $ 2.54 $ 3.74 Oil: Production (000's of barrels) 1,856 1,968 2,042 Average realized price (including hedges) $27.25 $22.80 $24.59 Average realized price (excluding hedges) $28.42 $23.26 $23.72 Production costs, including taxes, per net equivalent Mcf: Lease operating costs $ .48 $ .46 $ .53 Gathering and transportation .22 .20 .11 Production and property taxes .32 .21 .20 $ 1.02 $ .87 $ .84 Well and Acreage Information -- Gross and net productive well counts and gross and net developed and undeveloped acreage related to interests at December 31, 2003, are as follows: Gross Net Productive Wells: Natural Gas 2,678 2,155 Oil 2,178 130 Total 4,856 2,285 Developed Acreage (000's) 829 358 Undeveloped Acreage (000's) 1,275 863 Exploratory and Development Wells -- The following table reflects activities relating to Fidelity's natural gas and oil wells drilled and/or tested during 2003, 2002 and 2001: Net Exploratory Net Development Productive Dry Holes Total Productive Dry Holes Total Total 2003 10 2 12 274 2 276 288 2002 4 --- 4 201 --- 201 205 2001 19 1 20 590 2 592 612 At December 31, 2003, there were 118 gross wells in the process of drilling or under evaluation, 113 of which were development wells and five of which were exploratory wells. These wells are not included in the above table. Fidelity expects to complete drilling and testing the majority of these wells within the next 12 months. Environmental Matters -- WBI Holdings' natural gas and oil production operations are generally subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations. WBI Holdings believes it is in substantial compliance with these regulations. The ongoing operations of Fidelity are subject to the Clean Water Act and other federal and state environmental regulations. Administration of many provisions of the federal laws has been delegated to the states where Fidelity operates, and permit terms vary. Some permits have terms ranging from one to five years and others have no expiration date. Some of Fidelity's operations are subject to Section 404 of the Clean Water Act as administered by the Army Corps. Section 404 permits are required for operations that may affect waters of the United States, including operations in wetlands. The expiration dates of these permits also vary, with five years generally being the longest term. Detailed environmental assessments and/or environmental impact statements under federal and state laws are required as part of the permitting process incident to commencement of drilling and production operations as well as in abandonment proceedings. In connection with the development of coalbed natural gas properties, certain capital expenditures were incurred related to water handling. For 2003, capital expenditures for water handling in compliance with current laws and regulations were approximately $2.0 million and are estimated to be less than $3.0 million per year through 2006. For information regarding coalbed natural gas legal proceedings, see Item 3 -- Legal Proceedings, Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors and Cautionary Statements that May Affect Future Results - Environmental and Regulatory Risks and Item 8 -- Financial Statements and Supplementary Data - Note 19. Reserve Information -- Fidelity's recoverable proved developed and undeveloped natural gas and oil reserves approximated 411.7 Bcf and 18.9 million barrels, respectively, at December 31, 2003. For additional information related to natural gas and oil interests, see Item 8 -- Financial Statements and Supplementary Data - Note 1 and Supplementary Financial Information. CONSTRUCTION MATERIALS AND MINING Construction Materials: General -- Knife River operates construction materials and mining businesses in Alaska, California, Hawaii, Iowa, Minnesota, Montana, North Dakota, Oregon, Texas and Wyoming. These operations mine, process and sell construction aggregates (crushed stone, sand and gravel) and supply ready-mixed concrete for use in most types of construction, including homes, schools, shopping centers, office buildings and industrial parks as well as roads, freeways and bridges. In addition, certain operations produce and sell asphalt for various commercial and roadway applications. Although not common to all locations, other products include the sale of cement, various finished concrete products and other building materials and related construction services. During 2003, the Company acquired several construction materials and mining businesses with operations in Montana, North Dakota and Texas. None of these acquisitions were individually material to the Company. Knife River's construction materials business has continued to grow since its first acquisition in 1992. Knife River continues to investigate the acquisition of other construction materials properties, particularly those relating to sand and gravel aggregates and related products such as ready-mixed concrete, asphalt and various finished aggregate products. Knife River's construction materials business has benefited from the Transportation Equity Act for the 21st Century (TEA-21). TEA-21 expired on September 30, 2003, however funding is currently being provided under an extension of TEA-21 that expires on February 29, 2004. Although it is difficult to predict the outcome of legislation regarding federal highway construction funding that is anticipated to replace TEA-21, Knife River expects replacement funding to be equal to or higher than TEA-21. The construction materials business had approximately $399 million in backlog in mid-February 2004, compared to approximately $244 million in mid-February 2003. The Company anticipates that a significant amount of the current backlog will be completed during the year ending December 31, 2004. Competition -- Knife River's construction materials products are marketed under highly competitive conditions. Since there are generally no measurable product differences in the market areas in which Knife River conducts its construction materials businesses, price is the principal competitive force to which these products are subject, with service, delivery time and proximity to the customer also being significant factors. The number and size of competitors varies in each of Knife River's principal market areas and product lines. The demand for construction materials products is significantly influenced by the cyclical nature of the construction industry in general. In addition, construction materials activity in certain locations may be seasonal in nature due to the effects of weather. The key economic factors affecting product demand are changes in the level of local, state and federal governmental spending, general economic conditions within the market area which influence both the commercial and private sectors, and prevailing interest rates. Knife River is not dependent on any single customer or group of customers for sales of its construction materials products, the loss of which would have a materially adverse affect on its construction materials businesses. Reserve Information -- Reserve estimates are calculated based on the best available data. These data are collected from drill holes and other subsurface investigations, as well as investigations of surface features like mine highwalls and other exposures of the aggregate reserves. Mine plans, production history and geologic data are also utilized to estimate reserve quantities. Most acquisitions are made of mature businesses with established reserves, as distinguished from exploratory type properties. Estimates are based on analyses of the data described above by experienced mining engineers, operating personnel and geologists. Property setbacks and other regulatory restrictions and limitations are identified to determine the total area available for mining. Data described above are used to calculate the thickness of aggregate materials to be recovered. Topography associated with alluvial sand and gravel deposits is typically flat and volumes of these materials are calculated by simply applying the thickness of the resource over the areas available for mining. Volumes are then converted to tons by using an appropriate conversion factor. Typically, 1.5 tons per cubic yard in the ground is used for sand and gravel deposits. Topography associated with the hard rock reserves is typically much more diverse. Therefore, using available data, a final topography map is created and computer software is utilized to compute the volumes between the existing and final topographies. Volumes are then converted to tons by using an appropriate conversion factor. Typically, 2 tons per cubic yard in the ground is used for hard rock quarries. Estimated reserves are probable reserves as defined in Securities Act Industry Guide 7. Remaining reserves are based on estimates of volumes that can be economically extracted and sold to meet current market and product applications. The reserve estimates include only salable tonnage and thus exclude waste materials that are generated in the crushing and processing phases of the operation. Approximately 1.1 billion tons of the 1.2 billion tons of aggregate reserves are permitted reserves. The remaining reserves are on properties that we expect will be permitted for mining under current regulatory requirements. Some sites have leases that expire prior to the exhaustion of the estimated reserves. The estimated reserve life (years remaining) anticipates, based on Knife River's experience, that leases will be renewed to allow sufficient time to fully recover these reserves. The data used to calculate the remaining reserves may require revisions in the future to account for changes in customer requirements and unknown geological occurrences. The years remaining were calculated by dividing remaining reserves by current year sales. Actual useful lives of these reserves will be subject to, among other things, fluctuations in customer demand, customer specifications, geological conditions and changes in mining plans. The following table sets forth details applicable to the Company's aggregate reserves under ownership or lease as of December 31, 2003 and sales as of and for the years ended December 31, 2003, 2002 and 2001: [Enlarge/Download Table] Number Number of Sites of Sites Estimated Production (Crushed Stone) (Sand & Gravel) Tons Sold (000's) Reserves Lease Reserve Area owned leased owned leased 2003 2002 2001 (000's tons) Expiration Life (yrs) Central MN --- 1 52 58 6,265 6,236 3,860 113,768 2004-2028 18 Portland, OR 1 4 4 3 4,610 4,186 3,951 276,132 2005-2055 60 Northern CA --- --- 7 1 3,907 3,430 2,797 63,419 2046 16 Southwest OR 3 6 11 2 3,360 2,812 2,710 106,992 2004-2031 32 Eugene, OR 4 3 4 2 1,442 2,724 1,418 188,464 2006-2046 131 Hawaii --- 6 --- --- 2,134 2,688 1,528 71,630 2011-2037 34 Central MT --- --- 5 3 2,667 2,463 1,951 40,053 2011-2023 15 Anchorage, AK --- --- 1 --- 1,610 1,719 1,991 24,752 N/A 15 Northwest MT --- --- 8 5 1,413 1,260 1,197 33,374 2005-2020 24 Southern CA --- 2 --- --- 1,945 1,247 101 96,328 2035 50 Bend, OR --- 2 2 1 857 1,030 836 66,976 2010-2012 78 Northern MN 2 --- 21 21 873 559 --- 34,678 2004-2016 40 North/South --- --- 1 43 704 --- --- 43,776 2004-2031 62 Dakota Eastern TX 1 2 --- 3 449 --- --- 19,071 2005-2012 42 Casper, WY --- --- --- 1 172 61 67 2,000 2006 12 Sales from other sources 6,030 4,663 5,158 --- 38,438 35,078 27,565 1,181,413 The 1.2 billion tons of estimated aggregate reserves at December 31, 2003 is comprised of 531 million tons that are owned and 650 million tons that are leased. The leases have various expiration dates ranging from 2004 to 2055. Approximately 60 percent of the tons under lease have lease expiration dates of 20 years or more. The weighted average years remaining on all leases containing estimated probable aggregate reserves is approximately 23 years, including options for renewal that are at Knife River's discretion. Based on 2003 sales from leased reserves, the average time necessary to produce remaining aggregate reserves from such leases is approximately 44 years. The following table summarizes Knife River's aggregate reserves at December 31, 2003, 2002 and 2001 and reconciles the changes between these dates: 2003 2002 2001 (000's of tons) Aggregate Reserves: Beginning of year 1,110,020 1,065,330 894,500 Acquisitions 109,362 72,808 210,335 Sales volumes* (32,408) (30,415) (22,407) Other (5,561) 2,297 (17,098) End of year 1,181,413 1,110,020 1,065,330 _________________________________ *Excludes sales from other sources Coal: In 2001, the Company sold its coal operations to Westmoreland for $28.2 million in cash, including final settlement cost adjustments. For more information on the sale see information contained in Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations - 2002 compared to 2001 - Construction Materials and Mining. The sale of the Company's coal operations in 2001 included active coal mines in North Dakota and Montana, coal sales agreements, reserves and mining equipment, and certain development rights at the Company's former Gascoyne Mine site in North Dakota. The Company retained ownership of lignite deposits and leases at its former Gascoyne Mine site in North Dakota, which were not part of the sale of the coal operations. The Gascoyne Mine site was closed in 1995 due to the cancellation of the coal sales contract. These lignite deposits are currently not being mined and are not associated with an operating mine. These lignite deposits are of a high moisture content and it is not economical to mine and ship the lignite to other distant markets. However, should a power plant be constructed near the area, the Company may have the opportunity to participate in supplying lignite to fuel a plant. As of December 31, 2003, Knife River had under ownership or lease, deposits of approximately 26.9 million tons of recoverable lignite coal. Consolidated Construction Materials and Mining: Environmental Matters -- Knife River's construction materials and mining operations are subject to regulation customary for such operations, including federal, state and local environmental compliance and reclamation regulations. Except as what may be ultimately determined with regard to the Portland, Oregon Harbor Superfund Site issue described below, Knife River believes it is in substantial compliance with these regulations. Knife River's asphalt and ready-mixed concrete manufacturing plants and aggregate processing plants are subject to Clean Air Act and Clean Water Act requirements for controlling air emissions and water discharges. Some mining and construction activities are also subject to these laws. In the states where Knife River operates, these regulatory programs have been delegated to state and local regulatory authorities. Knife River's facilities are also subject to RCRA as it applies to underground storage tanks and the management of petroleum hydrocarbon products and wastes. These programs have also generally been delegated to the state and local authorities in the states where Knife River operates. No specific permits are required but Knife River's facilities must comply with requirements for managing petroleum hydrocarbon products and wastes. Some Knife River activities are directly regulated by federal agencies. For example, gravel bar skimming and deep water dredging operations are subject to provisions of the Clean Water Act that are administered by the Army Corps. Knife River operates nine gravel bar skimming operations and one deep water dredging operation in Oregon, all of which are subject to Army Corp permits as well as state permits. The expiration dates of these permits vary, with five years generally being the longest term. None of these in-water mining operations are included in Knife River's aggregate reserve numbers. Knife River's operations are also occasionally subject to the Endangered Species Act (ESA). For example, land use regulations often require environmental studies, including wildlife studies before a permit may be granted for a new or expanded mining facility. If endangered species or their habitats are identified, ESA requirements for protection, mitigation or avoidance apply. Endangered species protection requirements are usually included as part of land use permit conditions. Typical conditions include avoidance, setbacks, restrictions on operations during certain times of the breeding or rearing season, and construction or purchase of mitigation habitat. Knife River's operations are also subject to state and federal cultural resources protection laws when new areas are disturbed for mining operations. Mining permit applications generally require that areas proposed for mining be surveyed for cultural resources. If any are identified, they must be protected or managed in accordance with regulatory agency requirements. The most challenging environmental permit requirements are usually associated with new mining operations, although requirements vary widely from state to state and even within states. In some areas, land use regulations and associated permitting requirements are minimal. However, some states and local jurisdictions have very demanding requirements for permitting new mines. Environmental impact reports are sometimes required before a mining permit application can even be considered for approval. These reports can take up to several years to complete. The report can include projected impacts of the proposed project on air and water quality, wildlife, noise levels, traffic, scenic vistas, and other environmental factors. The reports generally include suggested actions to mitigate the projected adverse impacts. Provisions for public hearings and public comments are usually included in mine permit application review procedures in the counties where Knife River operates. After taking into account environmental, mine plan and reclamation information provided by the permittee as well as comments from the public and other regulatory agencies, the local authority approves or denies the permit application. Denial is rare but permits for mining often include conditions that must be addressed by the permittee. Conditions may include property line setbacks, reclamation requirements, environmental monitoring and reporting, operating hour restrictions, financial guarantees for reclamation, and other requirements intended to protect the environment or address concerns submitted by the public or other regulatory agencies. Despite the challenges, Knife River has been successful in obtaining mining permit approvals so that sufficient permitted reserves are available to support its operations. This often requires considerable advanced planning to ensure sufficient time is available to complete the permitting process before the newly permitted reserve is needed to support Knife River's operations. Knife River's Gascoyne surface coal mine last produced coal in 1995 but continues to be subject to reclamation requirements of the Surface Mining Control and Reclamation Act (SMCRA), as well as the North Dakota Surface Mining Act. Much of the property formerly occupied by the mine remains under reclamation bond pending completion of the ten year revegetation liability period under SMCRA. Knife River did not incur any material environmental expenditures in 2003 and except as what may be ultimately determined with regard to the issue described below, Knife River does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2006. In December 2000, Morse Bros., Inc. (MBI), an indirect wholly owned subsidiary of the Company, was named by the EPA as a Potentially Responsible Party in connection with the cleanup of a commercial property site, acquired by MBI in 1999, and part of the Portland, Oregon, Harbor Superfund Site. Sixty-eight other parties were also named in this administrative action. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. To date, costs of the overall remedial investigation of the harbor site for both the EPA and the Oregon State Department of Environmental Quality (DEQ) are being recorded, and initially paid, through an administrative consent order by the Lower Willamette Group (LWG), a group of 10 entities which does not include MBI. The LWG estimates the overall remedial investigation and feasibility study will cost approximately $10 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and feasibility study has been completed, the EPA has decided on a strategy, and a record of decision has been published. While the remedial investigation and feasibility study for the harbor site has commenced, it is expected to take several years to complete. The development of a proposed plan and record of decision on the harbor site is not anticipated to occur until 2006, after which a cleanup plan will be undertaken. Based upon a review of the Portland Harbor sediment contamination evaluation by the DEQ and other information available, MBI does not believe it is a Responsible Party. In addition, MBI has notified Georgia-Pacific West, Inc., the seller of the commercial property site to MBI, that it intends to seek indemnity for any and all liabilities incurred in relation to the above matters, pursuant to the terms of their sale agreement. The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above administrative action. INDEPENDENT POWER PRODUCTION AND OTHER Centennial Resources owns electric generating facilities in the United States and has an investment in an electric generating facility in Brazil. Electric capacity and energy produced at these facilities are primarily sold under long-term contracts to nonaffiliated entities. Centennial Resources includes investments in potential new growth opportunities that are not directly being pursued by the other business units, as well as projects outside the United States which are consistent with the Company's philosophy, growth strategy and areas of expertise. Substantially all of the operations of the independent power production business began in 2002. Domestic: On November 1, 2002, Centennial Power, Inc. (Centennial Power), an indirect wholly owned subsidiary of the Company, purchased 213 megawatts of natural gas-fired electric generating facilities (Brush Plant) near Brush, Colorado. Ninety-five percent of the Brush Plant's output is sold to the Public Service of Colorado, a wholly owned subsidiary of Xcel Energy, under two power purchase contracts that expire in October 2005 and September 2012, respectively. The Brush Plant is operated by Colorado Energy Management under two operations and maintenance agreements that expire in October 2005 and April 2007, respectively. On January 31, 2003, Centennial Power purchased a 66.6-megawatt wind-powered electric generating facility from San Gorgonio Power Corporation, an affiliate of PG&E National Energy Group. This facility is located in the San Gorgonio Pass, northwest of Palm Springs, California. The facility consists of 111 wind turbines and began commercial operation in September 2001. The facility sells all of its output under a contract with the California Department of Water Resources that expires in September 2011. The facility is connected to the Southern California Edison Company Power transmission system. SeaWest Wind Power, Inc. (SeaWest) is under a contract to operate the facility. The contract with SeaWest expires in October 2013. Competition -- Centennial Power encounters competition in the development of new electric generating plants and the acquisition of existing generating facilities from other non-utility generators, regulated utilities, nonregulated subsidiaries of regulated utilities and other energy service companies as well as financial investors. Competition for power sales agreements may reduce power prices in certain markets. The movement towards deregulation in the U.S. electric power industry has also lead to competition in the development and acquisition of domestic power producing facilities. However, some states are reconsidering their approaches to deregulation. Factors for competing in the power production industry include maintaining low production costs, having a balanced portfolio of generating assets, fuel types, customers and power sales agreements. Environmental Matters -- Centennial Power has several operations that require federal or state environmental permits. The Brush Plant, in Colorado, is subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations and state hazard communication standards. Centennial Power believes it is in substantial compliance with these regulations. The Brush Plant in Colorado has a Title V Operating Permit issued by the state for a period of five years, under a program approved by the EPA. The plant also has a water discharge agreement to release process water to the City of Brush. This agreement has no specific termination date as long as the Brush Plant is operating in compliance with the agreement. The Mountain View wind-powered electric generating facility has obtained necessary siting authority and federal land leases for its operations. It has minor requirements related to water management and spill control under the Clean Water Act, administered by the state. Centennial Power did not incur any material environmental expenditures in 2003 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2006. Other -- Rocky Mountain Power, an indirect wholly owned subsidiary of Centennial Resources, has begun construction of a 113-megawatt coal-fired development project in Hardin, Montana. Based on demand and power pricing in the Northwest, the plant is being built on a merchant basis. Efforts will continue towards securing a contract for the off-take of this plant. The projected on-line date for this plant is late 2005. For additional information regarding this plant, see Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors and Cautionary Statements that May Affect Future Results - Risks Relating to the Company's Independent Power Production Business, and - Prospective Information - Independent power production and other. International: In August 2001, MDU Brasil Ltda. (MDU Brasil), an indirect wholly owned Brazilian subsidiary of the Company, entered into a joint venture agreement with a Brazilian firm under which the parties formed MPX Participacoes, Ltda. (MPX) to develop electric generation and transmission, steam generation, power equipment and coal mining projects in Brazil. MDU Brasil has a 49 percent interest in MPX. MPX, through a wholly owned subsidiary, owns a 220-megawatt natural gas-fired electric generating facility (Brazil Generating Facility) in the Brazilian state of Ceara. The first two turbines of the Brazil Generating Facility entered commercial operations in July 2002. The remaining two turbines entered commercial operations in January 2003. Petrobras, the Brazilian state-controlled energy company, has agreed to purchase all of the capacity and market all of the Brazil Generating Facility's energy. The power purchase agreement with Petrobras expires in May 2008. Petrobras also is under contract to supply natural gas to the Brazil Generating Facility during the term of the power purchase agreement. This natural gas supply contract is renewable by a wholly owned subsidiary of MPX for an additional 13 years. At December 31, 2003, Centennial Resource's investment in the Brazil Generating Facility was approximately $25.2 million, including undistributed earnings of $4.6 million. Environmental Matters -- The Brazil Generating Facility is subject to all Brazilian federal environmental statutes. IBAMA, the Brazilian government regulatory agency or Brazilian Environment Institute, oversees all environmental issues within Brazil. SEMACE, the state of Ceara regulatory body or state of Ceara Environmental Superintendency, annually issues an operating license to MPX. MPX maintains and must annually renew its operating license that is granted by SEMACE. SEMACE requires air and water monitoring on a regular basis. ANEEL, the Brazilian federal electric regulatory body, provides environmental guidance with which MPX must comply. MPX is in material compliance with all applicable environmental regulations and permit requirements. MPX did not incur any material environmental expenditures in 2003 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2006. ITEM 3. LEGAL PROCEEDINGS In June 1997, Jack J. Grynberg (Grynberg) filed a Federal False Claims Act suit against Williston Basin and Montana-Dakota and filed over 70 similar suits against natural gas transmission companies and producers, gatherers, and processors of natural gas. Grynberg, acting on behalf of the United States under the Federal False Claims Act, alleged improper measurement of the heating content and volume of natural gas purchased by the defendants resulting in the underpayment of royalties to the United States. In April 1999, the United States Department of Justice decided not to intervene in these cases. In response to a motion filed by Grynberg, the Judicial Panel on Multidistrict Litigation consolidated all of these cases in the Federal District Court of Wyoming. The matter is currently in the discovery stage. Grynberg has not specified the amount he seeks to recover. Williston Basin and Montana-Dakota are unable to estimate their potential exposure and will be unable to do so until discovery is completed. Williston Basin and Montana-Dakota believe that the Grynberg case will ultimately be dismissed because Grynberg is not, as is required by the Federal False Claims Act, the original source of the information underlying the action. Failing this, Williston Basin and Montana-Dakota believe Grynberg will not recover damages from Williston Basin and Montana-Dakota because insufficient facts exist to support the allegations. Williston Basin and Montana-Dakota believe the claims of Grynberg are without merit and intend to vigorously contest this suit. Williston Basin and Montana-Dakota believe it is not probable that Grynberg will ultimately succeed given the current status of the litigation. Fidelity has been named as a defendant in, and/or certain of its operations are subject of, 11 lawsuits filed in connection with its coalbed natural gas development in the Powder River Basin in Montana and Wyoming. These lawsuits were filed in federal and state courts in Montana between June 2000 and December 2003 by a number of environmental organizations, including the Northern Plains Resource Council and the Montana Environmental Information Center as well as the Tongue River Water Users' Association and the Northern Cheyenne Tribe. Two of the lawsuits have been transferred to Federal District Court in Wyoming. The lawsuits involve allegations that Fidelity and/or various government agencies are in violation of state and/or federal law, including the Clean Water Act and the National Environmental Policy Act. The lawsuits seek injunctive relief, invalidation of various permits and unspecified damages. Fidelity is unable to quantify the damages sought, and will be unable to do so until after completion of discovery. Fidelity is vigorously defending all coalbed-related lawsuits in which it is involved. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could have a material effect on Fidelity's existing coalbed natural gas operations and/or the future development of its coalbed natural gas properties. Montana-Dakota has joined with two electric generators in appealing a finding by the North Dakota Department of Health (Department) in September 2003 that the Department may unilaterally revise operating permits previously issued to electric generating plants. Although it is doubtful that any revision of Montana-Dakota's operating permits by the Department would reduce the amount of electricity its plants could generate, the finding, if allowed to stand, could increase costs for sulfur dioxide removal and/or limit Montana-Dakota's ability to modify or expand operations at its North Dakota generation sites. Montana-Dakota and the other electric generators filed their appeal of the order on October 8, 2003, in the Burleigh County District Court in Bismarck, North Dakota. Proceedings have been stayed pending discussions with the EPA, the Department and the other electric generators. In a related case, the Dakota Resource Council filed an action in Federal District Court in Denver, Colorado, on September 30, 2003, to require the EPA to enforce certain air quality standards in North Dakota. If successful, the action could require the curtailment of discharges of sulfur dioxide into the atmosphere by existing electric generating facilities and could preclude or hinder the construction of future generating facilities in North Dakota. The Company has filed a motion to Intervene in the lawsuit and has joined in a brief supporting a Motion to Dismiss filed by the EPA. The Company cannot predict the outcome of the Department or Dakota Resource Council matters or their ultimate impact on its operations. In December 2000, MBI, an indirect wholly owned subsidiary of the Company, was named by the EPA as a Potentially Responsible Party in connection with the cleanup of a commercial property site, acquired by MBI in 1999, and part of the Portland, Oregon, Harbor Superfund Site. For additional information regarding this matter, see Items 1 and 2 -- Business and Properties - Consolidated Construction Materials and Mining - Environmental Matters. 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 2003. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS The Company's common stock is listed on the New York Stock Exchange and the Pacific Stock Exchange under the symbol "MDU." The price range of the Company's common stock as reported by The Wall Street Journal composite tape during 2003 and 2002 and dividends declared thereon were as follows: Common Common Common Stock Stock Price Stock Price Dividends (High)* (Low)* Per Share* 2003 First Quarter $ 18.87 $ 16.41 $ .1600 Second Quarter 22.66 18.55 .1600 Third Quarter 23.32 20.37 .1700 Fourth Quarter 24.35 22.23 .1700 $ .6600 2002 First Quarter $ 20.73 $ 18.17 $ .1533 Second Quarter 22.30 17.17 .1533 Third Quarter 18.27 12.00 .1600 Fourth Quarter 17.33 13.94 .1600 $ .6266 __________________________ * Reflects the Company's three-for-two common stock split effected in October 2003. As of December 31, 2003, the Company's common stock was held by approximately 14,900 stockholders of record. Between October 1, 2003 and December 31, 2003, the Company issued 118,570 shares of Common Stock, $1.00 par value, as a final adjustment with respect to an acquisition in a prior period. The Common Stock and Rights issued by the Company in these transactions were issued in a private transaction exempt from registration under the Securities Act of 1933 pursuant to Section 4(2) thereof, Rule 506 promulgated thereunder, or both. The classes of persons to whom these securities were sold were either accredited investors or other persons to whom such securities were permitted to be offered under the applicable exemption. ITEM 6. SELECTED FINANCIAL DATA [Enlarge/Download Table] MDU RESOURCES GROUP, INC. OPERATING STATISTICS 2003 2002 2001 2000 1999 1998* Selected Financial Data Operating revenues (000's): Electric $ 178,562 $ 162,616 $ 168,837 $ 161,621 $ 154,869 $ 147,221 Natural gas distribution 274,608 186,569 255,389 233,051 157,692 154,147 Utility services 434,177 458,660 364,750 169,382 99,917 64,232 Pipeline and energy services 252,192 165,258 531,114 636,848 383,532 180,732 Natural gas and oil production 264,358 203,595 209,831 138,316 78,394 61,842 Construction materials and mining 1,104,408 962,312 806,899 631,396 469,905 346,451 Independent power production and other 34,989 6,776 --- --- --- --- Intersegment eliminations (191,105) (114,249) (113,188) (96,943) (64,500) (57,998) $2,352,189 $2,031,537 $2,223,632 $1,873,671 $1,279,809 $ 896,627 Operating income (000's): Electric $ 35,761 $ 33,915 $ 38,731 $ 38,743 $ 35,727 $ 32,167 Natural gas distribution 6,502 2,414 3,576 9,530 6,688 8,028 Utility services 12,885 13,980 25,199 16,606 11,518 5,932 Pipeline and energy services 35,155 39,091 30,368 28,782 40,627 33,651 Natural gas and oil production 118,347 85,555 103,943 66,510 26,845 (50,444) Construction materials and mining 91,579 91,430 71,451 56,816 38,346 41,609 Independent power production and other 11,843 (268) --- --- --- --- $ 312,072 $ 266,117 $ 273,268 $ 216,987 $ 159,751 $ 70,943 Earnings on common stock (000's): Electric $ 16,950 $ 15,780 $ 18,717 $ 17,733 $ 15,973 $ 13,908 Natural gas distribution 3,869 3,587 677 4,741 3,192 3,501 Utility services 6,170 6,371 12,910 8,607 6,505 3,272 Pipeline and energy services 18,158 19,097 16,406 10,494 20,972 18,651 Natural gas and oil production 70,767** 53,192 63,178 38,574 16,207 (30,501) Construction materials and mining 54,261** 48,702 43,199 30,113 20,459 24,499 Independent power production and other 12,021 959 --- --- --- --- Earnings on common stock before cumulative effect of accounting change 182,196** 147,688 155,087 110,262 83,308 33,330 Cumulative effect of accounting change (7,589) --- --- --- --- --- $ 174,607 $ 147,688 $ 155,087 $ 110,262 $ 83,308 $ 33,330 Earnings per common share before cumulative effect of accounting change -- diluted $ 1.62** $ 1.38 $ 1.52 $ 1.20 $ 1.01 $ .44 Cumulative effect of accounting change (.07) --- --- --- --- --- $ 1.55 $ 1.38 $ 1.52 $ 1.20 $ 1.01 $ .44 Pro forma amounts assuming retroactive application of accounting change: Net income (000's) $ 182,913 $ 146,052 $ 152,933 $ 108,951 $ 82,932 $ 33,253 Earnings per common share -- diluted $ 1.62 $ 1.36 $ 1.49 $ 1.17 $ 1.00 $ .43 Common Stock Statistics Weighted average common shares outstanding -- diluted (000's) 112,460 106,863 101,803 92,085 82,306 76,255 Dividends per common share $ .6600 $ .6266 $ .6000 $ .5733 $ .5467 $ .5223 Book value per common share $ 12.66 $ 11.56 $ 10.60 $ 9.03 $ 7.83 $ 6.93 Market price per common share (year-end) $ 23.81 $ 17.21 $ 18.77 $ 21.67 $ 13.33 $ 17.54 Market price ratios: Dividend payout 43% 45% 39% 48% 54% 119% Yield 2.9% 3.7% 3.3% 2.7% 4.2% 3.0% Price/earnings ratio 15.4x 12.5x 12.3x 18.1x 13.2x 39.9x Market value as a percent of book value 188.1% 148.8% 177.0% 239.9% 170.4% 253.2% Profitability Indicators Return on average common equity 13.0% 12.5% 15.3% 14.3% 13.9% 6.5% Return on average invested capital 8.9% 8.6% 10.1% 9.5% 9.6% 5.5% Interest coverage 7.4x 7.7x 8.5x 8.3x 7.1x 6.1x Fixed charges coverage, including preferred dividends 4.7x 4.8x 5.3x 4.1x 4.3x 2.5x General Total assets (000's) $3,380,592 $2,996,921 $2,675,978 $2,358,981 $1,806,648 $1,488,713 Net long-term debt (000's) $ 939,450 $ 819,558 $ 783,709 $ 728,166 $ 563,545 $ 413,264 Redeemable preferred stock (000's) $ --- $ 1,300 $ 1,400 $ 1,500 $ 1,600 $ 1,700 Capitalization ratios: Common equity 60% 60% 58% 54% 54% 56% Preferred stocks 1 1 1 1 1 2 Long-term debt 39 39 41 45 45 42 100% 100% 100% 100% 100% 100% <FN> * Reflects $39.9 million or 52 cents per common share in noncash after-tax write-downs of natural gas and oil properties. ** Before cumulative effect of the change in accounting for asset retirement obligations required by the adoption of SFAS No. 143, as discussed in Notes 1 and 9. NOTE: Common stock share amounts reflect the Company's three-for-two common stock splits effected in July 1998 and October 2003. </FN> [Enlarge/Download Table] 2003 2002 2001 2000 1999 1998 Electric Retail sales (thousand kWh) 2,359,888 2,275,024 2,177,886 2,161,280 2,075,446 2,053,862 Sales for resale (thousand kWh) 841,637 784,530 898,178 930,318 943,520 586,540 Electric system summer generating and firm purchase capability -- kW (Interconnected system) 542,680 500,570 500,820 500,420 492,800 489,100 Demand peak -- kW (Interconnected system) 470,470 458,800 453,000 432,300 420,550 402,500 Electricity produced (thousand kWh) 2,384,884 2,316,980 2,469,573 2,331,188 2,350,769 2,103,199 Electricity purchased (thousand kWh) 929,439 857,720 792,641 948,700 860,508 730,949 Average cost of fuel and purchased power per kWh $.019 $.018 $.018 $.016 $.016 $.017 Natural Gas Distribution Sales (Mdk) 38,572 39,558 36,479 36,595 30,931 32,024 Transportation (Mdk) 13,903 13,721 14,338 14,314 11,551 10,324 Weighted average degree days -- % of previous year's actual 96% 109% 95% 113% 95% 94% Pipeline and Energy Services Transportation (Mdk) 90,239 99,890 97,199 86,787 78,061 88,974 Gathering (Mdk) 75,861 72,692 61,136 41,717 19,799 9,093 Natural Gas and Oil Production Production: Natural gas (MMcf) 54,727 48,239 40,591 29,222 24,652 20,699 Oil (000's of barrels) 1,856 1,968 2,042 1,882 1,758 1,912 Average realized prices: Natural gas (per Mcf) $ 3.90 $ 2.72 $ 3.78 $ 2.90 $ 1.94 $ 1.81 Oil (per barrel) $27.25 $22.80 $24.59 $23.06 $15.34 $12.71 Net recoverable reserves: Natural gas (MMcf) 411,700 372,500 324,100 309,800 268,900 243,600 Oil (000's of barrels) 18,900 17,500 17,500 15,100 14,700 11,500 Construction Materials and Mining Construction materials (000's): Aggregates (tons sold) 38,438 35,078 27,565 18,315 13,981 11,054 Asphalt (tons sold) 7,275 7,272 6,228 3,310 2,993 1,790 Ready-mixed concrete (cubic yards sold) 3,484 2,902 2,542 1,696 1,186 1,021 Recoverable aggregate reserves (tons) 1,181,400 1,110,020 1,065,330 894,500 740,030 654,670 Coal (000's): Sales (tons) ---* ---* 1,171* 3,111 3,236 3,113 Lignite deposits (tons) 26,910* 37,761* 56,012* 145,643 182,761 190,152 Independent Power Production and Other** Net generation capacity -- kW 279,600 213,000 --- --- --- --- Electricity produced and sold (thousand kWh) 270,044 15,804 --- --- --- --- <FN> * Coal operations were sold effective April 30, 2001. ** Reflects domestic independent power production operations acquired in November 2002 and January 2003. </FN> ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview This subsection of Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations (Management's Discussion and Analysis) is a brief overview of the important factors that management focuses on in evaluating the Company's businesses, the Company's financial condition and operating performance, the Company's overall business strategy and the earnings of the Company for the period covered by this report. This subsection is not intended to be a substitute for reading the entire Management's Discussion and Analysis section. Reference is made to the various important factors listed under the heading Risk Factors and Cautionary Statements that May Affect Future Results, as well as other factors that are listed in Part I in relation to any forward-looking statement. Business and Strategy Overview The Company has six reportable segments consisting of electric, natural gas distribution, utility services, pipeline and energy services, natural gas and oil production, and construction materials and mining. During the fourth quarter of 2002, the Company separated independent power production and other operations from its reportable segments. The independent power production and other operations do not individually meet the criteria to be considered a reportable segment. Substantially all of the operations of independent power production and other began in 2002; therefore, financial information for years prior to 2002 has not been presented. The electric and natural gas distribution segments include the electric and natural gas distribution operations of Montana- Dakota and the natural gas distribution operations of Great Plains Natural Gas Co. The utility services segment includes all the operations of Utility Services, Inc. The pipeline and energy services segment includes WBI Holdings' natural gas transportation, underground storage, gathering services, and energy-related management services. The natural gas and oil production segment includes the natural gas and oil acquisition, exploration and production operations of WBI Holdings. The construction materials and mining segment includes the results of Knife River's operations. Independent power production and other operations own electric generating facilities in the United States and have an investment in an electric generating facility in Brazil and investments in opportunities that are not directly being pursued by the Company's other businesses. Earnings from electric, natural gas distribution, and pipeline and energy services are substantially all from regulated operations. Earnings from utility services, natural gas and oil production, construction materials and mining, and independent power production and other are all from nonregulated operations. On August 14, 2003, the Company's Board of Directors approved a three-for-two common stock split. For more information on the common stock split, see Item 8 -- Financial Statements and Supplementary Data - Note 11. The Company's strategy is to pursue growth opportunities by expanding upon its expertise in energy and transportation infrastructure industries, focusing on acquiring and developing well-managed companies and projects that enhance shareholder value and are accretive to earnings per share and returns on invested capital. The Company's long-term compound annual growth goals on earnings per share from operations are in the range of 6 percent to 9 percent. In addition, earnings per share for 2004, diluted, are projected in the range of $1.55 to $1.68. Contributing to the anticipated growth goals and/or earnings per share projections are a number of items including: - Expected returns in 2004 at the electric business are anticipated to be generally consistent with authorized levels. - The Company expects to seek natural gas rate increases from time to time to offset higher expected operating costs at the natural gas distribution business. - Anticipated increased margins in 2004 compared to 2003 at the utility services business. - An expected increase of total natural gas throughput of approximately 25 percent to 30 percent over 2003 levels at the pipeline and energy services business, largely due to the 253- mile Grasslands Pipeline, which began providing natural gas transmission service on December 23, 2003. - Transportation rates are expected to decline in 2004 from 2003 levels due to the estimated effects of a FERC rate order received in July 2003. - An expected natural gas and oil production increase of approximately 10 percent in 2004 compared to 2003. - Natural gas prices in the Rocky Mountain region for February through December 2004 reflected in the Company's 2004 earnings guidance are in the range of $3.25 to $3.75 per Mcf. The Company's estimates for natural gas prices on the NYMEX for February through December 2004, reflected in the Company's 2004 earnings guidance, are in the range of $4.00 to $4.50 per Mcf. - The Company has hedged a portion of its 2004 estimated annual natural gas production. The Company has entered into agreements representing approximately 30 percent to 35 percent of 2004 estimated annual natural gas production. The agreements are at various indices and range from a low CIG index of $3.75 to a high CIG index of $5.48 per Mcf. CIG is an index pricing point related to Colorado Interstate Gas Co.'s system. - NYMEX crude oil prices for January through December 2004, reflected in the Company's 2004 earnings guidance, are in the range of $26 to $30 per barrel. - The Company has hedged a portion of its 2004 oil production. The Company has entered into agreements at NYMEX prices with a low of $28.84 and a high of $30.28, representing approximately 30 percent to 35 percent of 2004 estimated annual oil production. - An expected increase in 2004 revenues of approximately 5 percent to 10 percent over 2003 levels at the construction materials and mining business. - Anticipated earnings in the range of $18 million to $23 million in 2004 at the independent power production and other businesses. The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper credit facilities and through the issuance of long-term debt and the Company's equity securities. Net capital expenditures for 2003 were $474 million and are estimated to be approximately $370 million for 2004. The Company faces certain challenges and risks as it pursues its growth strategies, including, but not limited to the following: - The natural gas and oil production business experienced higher average natural gas and oil prices in 2003 compared to 2002. These prices are volatile and subject to significant change at any time. The Company hedges a portion of its natural gas and oil production in order to mitigate price volatility. - The soft economy and the depressed telecommunications market have been challenging particularly for the Company's utility services business, which has been subjected to lower margins and decreased workloads. These economic factors have also negatively affected the Company's energy services business. - Fidelity continues to seek additional reserve and production growth through acquisition, exploration, development and production of natural gas and oil resources, including the development and production of its coalbed natural gas properties. Future growth is dependent upon success in these endeavors. Fidelity has been named as a defendant in, and/or certain of its operations are the subject of, 11 lawsuits filed in connection with its coalbed natural gas development in the Powder River Basin in Montana and Wyoming. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could have a material effect on Fidelity's existing coalbed natural gas operations and/or the future development of its coalbed natural gas properties. For further information on certain factors that should be considered for a better understanding of the Company's financial condition, see the various important factors listed under the heading Risk Factors and Cautionary Statements that May Affect Future Results, as well as other factors that are listed in Part I. For information pertinent to various commitments and contingencies, see Items 1 and 2 -- Business and Properties, Item 3 -- Legal Proceedings and Item 8 -- Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements. Earnings Overview The following table (dollars in millions, where applicable) summarizes the contribution to consolidated earnings by each of the Company's businesses. Years ended December 31, 2003 2002 2001 Electric $ 16.9 $ 15.8 $ 18.7 Natural gas distribution 3.9 3.6 .7 Utility services 6.2 6.4 12.9 Pipeline and energy services 18.2 19.1 16.4 Natural gas and oil production 63.0 53.2 63.2 Construction materials and mining 54.4 48.7 43.2 Independent power production and other 12.0 .9 --- Earnings on common stock $ 174.6 $ 147.7 $ 155.1 Earnings per common share - basic $ 1.57 $ 1.39 $ 1.54 Earnings per common share - diluted $ 1.55 $ 1.38 $ 1.52 Return on average common equity 13.0% 12.5% 15.3% 2003 compared to 2002 Consolidated earnings for 2003 increased $26.9 million from the comparable prior period. Contributing to the earnings increase were higher earnings at the independent power production and other businesses primarily resulting from the acquisition of the Colorado and California electric generating facilities acquired in late 2002 and early 2003, respectively, and higher income from the Company's share of its equity investment in Brazil. Increased earnings at the natural gas and oil production business were primarily due to higher natural gas and oil prices and natural gas production, offset in part by the absence in 2003 of the 2002 compromise agreement gain of $27.4 million ($16.6 million after tax) which was included in 2002 operating revenues and the $12.7 million ($7.7 million after tax) noncash transition charge in 2003, reflecting the cumulative effect of an accounting change, as discussed in Item 8 -- Financial Statements and Supplementary Data - Note 19 and Note 9, respectively, and higher depreciation, depletion and amortization expense. Earnings increased at the construction materials and mining business due to higher aggregate volumes and margins and higher ready-mixed concrete volumes at existing operations; partially offset by lower asphalt margins; higher selling, general and administrative costs; and higher depreciation, depletion and amortization expense. Stronger sales for resale volumes and margins and higher retail volumes at the electric business and rate relief approved by various public service commissions at the natural gas distribution business, partially offset by higher operation and maintenance expense at both these businesses, also added to the increase in earnings. In addition, earnings at the natural gas distribution business increased due to the absence in 2003 of an adjustment of $3.3 million (after tax) in 2002 related to certain pipeline capacity charges, partially offset by higher income taxes in 2003, the result of the reversal of certain tax contingency reserves in 2002. Decreased earnings at the pipeline and energy services and utility services businesses slightly offset the earnings increase. Lower workloads and margins at the utility services business are a reflection of the continuing effects of the soft economy and the downturn in the telecommunications market. 2002 compared to 2001 Consolidated earnings for 2002 decreased $7.4 million from the comparable prior period. Lower earnings at the natural gas and oil production business were largely due to lower realized natural gas and oil prices offset in part by the previously mentioned compromise agreement gain and higher natural gas production. Also adding to the decrease in earnings were lower earnings at the utility services business due to decreased margins in the Rocky Mountain and Central regions and the write- off of certain receivables and restructuring of the engineering function, partially offset by increased workloads in the Southwest and Northwest regions. Decreased sales for resale prices partially offset by increased retail sales revenues at the electric business also added to the decrease in earnings. Partially offsetting the earnings decrease were higher earnings at the construction materials and mining business due to earnings from businesses acquired since the comparable prior period, higher aggregate, asphalt and cement sales volumes, and increased construction revenues, partially offset by the 2001 gain from the sale of the Company's coal operations of $10.3 million ($6.2 million after tax, including final settlement cost adjustments), included in 2001 other income - net, as discussed in Item 8 -- Financial Statements and Supplementary Data - Note 14. Also partially offsetting the earnings decrease were higher earnings at the natural gas distribution business due to higher retail sales volumes and lower income taxes, largely the result of the reversal of certain tax contingency reserves, partially offset by an adjustment of $3.3 million (after tax) related to certain pipeline capacity charges. Higher gathering revenues, partially offset by the net effects of the sale of certain smaller nonstrategic properties in 2001 at the pipeline and energy services business, and earnings from the independent power production and other businesses, also slightly offset the earnings decline. Financial and Operating Data The following tables (dollars in millions, where applicable) are key financial and operating statistics for each of the Company's businesses. Electric Years ended December 31, 2003 2002 2001 Operating revenues: Retail sales $ 148.1 $ 142.1 $ 137.3 Sales for resale and other 30.5 20.5 31.5 178.6 162.6 168.8 Operating expenses: Fuel and purchased power 62.0 56.0 57.4 Operation and maintenance 52.9 46.0 45.6 Depreciation, depletion and amortization 20.2 19.6 19.5 Taxes, other than income 7.7 7.1 7.6 142.8 128.7 130.1 Operating income $ 35.8 $ 33.9 $ 38.7 Retail sales (million kWh) 2,359.9 2,275.0 2,177.9 Sales for resale (million kWh) 841.6 784.6 898.2 Average cost of fuel and purchased power per kWh $ .019 $ .018 $ .018 Natural Gas Distribution Years ended December 31, 2003 2002 2001 Operating revenues: Sales $ 270.2 $ 182.5 $ 251.3 Transportation and other 4.4 4.1 4.1 274.6 186.6 255.4 Operating expenses: Purchased natural gas sold 211.1 132.9 200.7 Operation and maintenance 41.8 36.5 36.6 Depreciation, depletion and amortization 10.0 9.9 9.4 Taxes, other than income 5.2 4.9 5.1 268.1 184.2 251.8 Operating income $ 6.5 $ 2.4 $ 3.6 Volumes (MMdk): Sales 38.6 39.6 36.5 Transportation 13.9 13.7 14.3 Total throughput 52.5 53.3 50.8 Degree days (% of normal)* 97.3% 101.1% 94.5% Average cost of natural gas, including transportation thereon, per dk $ 5.47 $ 3.22 $ 5.50 ______________________________ * Degree days are a measure of the daily temperature-related demand for energy for heating. Utility Services Years ended December 31, 2003 2002 2001 Operating revenues $ 434.2 $ 458.7 $ 364.8 Operating expenses: Operation and maintenance 395.9 419.0 321.0 Depreciation, depletion and amortization 10.3 9.9 8.4 Taxes, other than income 15.1 15.8 10.2 421.3 444.7 339.6 Operating income $ 12.9 $ 14.0 $ 25.2 Pipeline and Energy Services Years ended December 31, 2003 2002 2001 Operating revenues: Pipeline $ 97.2 $ 95.3 $ 87.1 Energy services 155.0 69.9 444.0 252.2 165.2 531.1 Operating expenses: Purchased natural gas sold 149.5 58.3 433.5 Operation and maintenance 46.6 47.3 47.1 Depreciation, depletion and amortization 15.0 14.8 14.3 Taxes, other than income 5.9 5.7 5.8 217.0 126.1 500.7 Operating income $ 35.2 $ 39.1 $ 30.4 Transportation volumes (MMdk): Montana-Dakota 34.1 33.3 34.1 Other 56.1 66.6 63.1 90.2 99.9 97.2 Gathering volumes (MMdk) 75.9 72.7 61.1 Natural Gas and Oil Production Years ended December 31, 2003 2002 2001 Operating revenues: Natural gas $ 213.5 $ 131.0 $ 153.2 Oil 50.6 42.1 47.7 Other .2 30.5* 8.9 264.3 203.6 209.8 Operating expenses: Purchased natural gas sold .1 .1 2.8 Operation and maintenance: Lease operating costs 31.6 27.5 27.8 Gathering and transportation 14.7 12.3 5.8 Other 17.2 15.8 16.8 Depreciation, depletion and amortization 61.0 48.7 41.7 Taxes, other than income: Production and property taxes 21.0 12.7 10.8 Other .4 .9 .2 146.0 118.0 105.9 Operating income $ 118.3 $ 85.6 $ 103.9 Production: Natural gas (MMcf) 54,727 48,239 40,591 Oil (000's of barrels) 1,856 1,968 2,042 Average realized prices (including hedges): Natural gas (per Mcf) $ 3.90 $ 2.72 $ 3.78 Oil (per barrel) $ 27.25 $ 22.80 $ 24.59 Average realized prices (excluding hedges): Natural gas (per Mcf) $ 4.28 $ 2.54 $ 3.74 Oil (per barrel) $ 28.42 $ 23.26 $ 23.72 Production costs, including taxes, per net equivalent Mcf: Lease operating costs $ .48 $ .46 $ .53 Gathering and transportation .22 .20 .11 Production and property taxes .32 .21 .20 $ 1.02 $ .87 $ .84 ______________________________ *Includes the effects of a compromise agreement gain of $27.4 million ($16.6 million after tax). Construction Materials and Mining Years ended December 31, 2003 2002 2001 Operating revenues: Construction materials $ 1,104.4 $ 962.3 $ 794.6 Coal ---* ---* 12.3* 1,104.4 962.3 806.9 Operating expenses: Operation and maintenance 924.2 797.7 673.1 Depreciation, depletion and amortization 63.6 54.4 46.6 Taxes, other than income 25.0 18.8 15.7 1,012.8 870.9 735.4 Operating income $ 91.6 $ 91.4 $ 71.5 Sales (000's): Aggregates (tons) 38,438 35,078 27,565 Asphalt (tons) 7,275 7,272 6,228 Ready-mixed concrete (cubic yards) 3,484 2,902 2,542 Coal (tons) ---* ---* 1,171* ______________________________ *Coal operations were sold effective April 30, 2001. Independent Power Production and Other Years ended December 31, 2003 2002 2001 Operating revenues $ 35.0 $ 6.8 $ --- Operating expenses: Operation and maintenance 15.0 6.4 --- Depreciation, depletion and amortization 8.2 .7 --- 23.2 7.1 --- Operating income (loss)** $ 11.8 $ (.3) $ --- Net generation capacity - kW*** 279,600 213,000 --- Electricity produced and sold (thousand kWh)*** 270,044 15,804 --- ______________________________ ** Reflects international operations for 2003 and 2002 and domestic operations acquired on November 1, 2002 and January 31, 2003. ***Reflects domestic independent power production operations. NOTE: The earnings from the Company's equity method investment in Brazil were included in other income - net and, thus, are not reflected in the above table. Amounts presented in the preceding tables for operating revenues, purchased natural gas sold and operation and maintenance expense will not agree with the Consolidated Statements of Income due to the elimination of intersegment transactions. The amounts (dollars in millions) relating to the elimination of intersegment transactions are as follows: Years ended December 31, 2003 2002 2001 Operating revenues $ 191.1 $ 114.3 $ 113.2 Purchased natural gas sold 176.5 98.8 107.7 Operation and maintenance 14.6 15.5 5.5 For further information on intersegment eliminations, see Item 8 -- Financial Statements and Supplementary Data - Note 14. 2003 compared to 2002 Electric Electric earnings increased as a result of 48 percent higher average sales for resale prices and 7 percent higher sales for resale volumes, both due to stronger sales for resale markets. Higher retail sales revenues, due primarily to higher retail sales volumes, largely to residential, commercial and large industrial customers, also added to the increase in earnings. Partially offsetting the earnings increase was higher operation and maintenance expenses, including repair and maintenance at certain electric generating stations, insurance and payroll- related costs. Increased fuel and purchased power costs related to sales for resale also partially offset the earnings increase. Natural Gas Distribution Earnings at the natural gas distribution business increased due to higher retail sales rates, the result of rate relief approved by various public service commissions. Also adding to the increase in earnings was the absence in 2003 of an adjustment of $3.3 million (after tax) in 2002 related to certain pipeline capacity charges. Partially offsetting the earnings increase were higher operation and maintenance expenses, primarily due to higher payroll-related costs, and higher income taxes in 2003, the result of the reversal of certain tax contingency reserves in 2002. Decreased returns on natural gas held in storage and lower retail sales volumes due to weather that was 4 percent warmer than last year, also partially offset the earnings increase. The pass-through of higher natural gas prices is reflected in the increase in both sales revenues and purchased natural gas sold. Utility Services Utility services earnings decreased slightly as a result of lower line construction workloads and margins in the Southwest and Central regions and lower workloads and margins in the telecommunications industry in the Rocky Mountain region. Increased selling, general and administrative expenses and lower inside electrical workloads and margins in the Central region also contributed to the decrease in earnings. Partially offsetting the earnings decrease were the absence in 2003 of the 2002 write-off of certain receivables and restructuring of the engineering function of approximately $5.2 million (after tax) and higher line construction margins in the Northwest and Rocky Mountain regions. Lower margins are a reflection of the continuing effects of the soft economy in this sector and the downturn in the telecommunications market. Pipeline and Energy Services Earnings at the pipeline and energy services business decreased as a result of reduced natural gas margins and lower technology services revenues at the energy services businesses. Also contributing to the decrease in earnings were lower transportation volumes, largely resulting from lower volumes transported to storage. Partially offsetting the earnings decrease were increased revenues from higher transportation reservation fees resulting from an increase in the level of firm services provided, higher gathering volumes of 4 percent and lower financing-related costs. The increase in energy services revenues and the related increase in purchased natural gas sold includes the effect of increases in natural gas prices since the comparable prior period. Natural Gas and Oil Production Natural gas and oil production earnings increased due to higher realized natural gas prices of 43 percent; higher natural gas production of 13 percent, primarily from enhanced natural gas production from operated properties located in the Rocky Mountain area; and higher average realized oil prices of 20 percent. Partially offsetting the earnings increase were the 2002 compromise agreement gain and the noncash transition charge in 2003, reflecting the cumulative effect of an accounting change, both as previously discussed. Also partially offsetting the earnings increase were increased depreciation, depletion and amortization expense due to higher natural gas production volumes and higher rates. The higher depreciation, depletion and amortization rates are attributable to increased costs of reserve additions and the effects of the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations." Higher lease operating expenses due in part to increased production, higher general and administrative costs, decreased oil production of 6 percent and higher interest expense also partially offset the earnings increase. Construction Materials and Mining Construction materials and mining earnings increased due to higher aggregate and ready-mixed concrete volumes and margins and higher construction activity, all at existing operations. Earnings from companies acquired since the comparable period last year also added to the earnings increase. Partially offsetting the increase in earnings were higher selling, general and administrative costs, including insurance, computer system support and payroll-related costs; higher depreciation, depletion and amortization expense primarily due to higher property, plant and equipment balances; and higher aggregate volumes produced. Lower asphalt margins from existing operations, due in part to higher asphalt oil costs, also partially offset the earnings increase. Independent Power Production and Other Earnings for the independent power production and other businesses increased largely from the domestic businesses acquired in late 2002 and early 2003, partially offset by higher interest expense, resulting from higher average debt balances relating to these acquisitions. Also adding to the earnings increase was higher net income of $3.7 million from the Company's share of its equity investment in Brazil due primarily to higher margins from higher capacity revenues, which resulted from all four units being in operation in 2003 compared to only two operational units in 2002 (effective July 2002), as well as from foreign currency gains from the revaluation of the Brazilian real, partially offset by the mark-to-market loss on an embedded derivative in the electric power contract and higher interest expense due to a full year of debt in 2003. 2002 compared to 2001 Electric Electric earnings decreased as a result of lower average realized sales for resale prices, which were 34 percent lower than the prior year, due to weaker demand in the sales for resale markets; the absence in 2002 of 2001 insurance recovery proceeds related to a 2000 outage at an electric generating station; and lower sales for resale volumes, which were 13 percent lower than the prior year. Partially offsetting the earnings decline were increased retail sales volumes, which were 4 percent higher than the prior year, primarily to residential, commercial and large industrial customers; decreased fuel and purchased power costs, largely lower demand charges resulting from the absence of a 2001 extended maintenance outage at an electric supplier's generating station; and increased retail sales prices, primarily demand revenue, which were partially offset by the North Dakota retail rate reduction. Natural Gas Distribution Earnings at the natural gas distribution business increased as a result of higher retail sales volumes, which were 8 percent higher than the prior year, largely the result of weather that was 9 percent colder than the prior period; increased return on natural gas storage, demand and prepaid commodity balances; increased retail sales prices, largely the result of rate increases in Minnesota, Montana and North Dakota; higher service and repair margins; and lower income taxes, largely the result of the reversal of certain tax contingency reserves. An adjustment of $3.3 million (after tax) related to certain pipeline capacity charges partially offset the earnings increase. The pass-through of lower natural gas prices resulted in the decrease in sales revenues and purchased natural gas sold. Utility Services Utility services earnings decreased as a result of lower line construction margins in the Rocky Mountain region related primarily to decreased fiber optic construction work; lower construction margins in the Central region due to decreased inside electrical work; the write-off of certain receivables and restructuring of the engineering function of approximately $5.2 million (after tax); and decreased equipment sales and margins. Partially offsetting the earnings decline were increased workloads in the Southwest and Northwest regions, the discontinuance of the amortization of goodwill in 2002 ($1.4 million after tax in 2001), and decreased interest expense, primarily due to lower debt balances. The increase in revenues and the related increase in operation and maintenance expenses resulted largely from businesses acquired since the comparable prior period. Pipeline and Energy Services Earnings at the pipeline and energy services business increased as a result of higher gathering revenues, largely increased gathering volumes, which were 19 percent higher than the prior year, at higher average rates, and higher stand-by fees; increased volumes transported on-system and off-system, at slightly higher average rates; and higher storage revenues. Also contributing to the earnings improvement were lower corporate development costs and the absence in 2002 of a 2001 write-off of an investment in a software development company of $699,000 (after tax). Partially offsetting the earnings increase were the net effects of the sale of certain smaller nonstrategic properties in 2001 along with higher operation and maintenance expenses and higher depreciation, depletion and amortization expense, a result of gathering system expansion to accommodate increasing natural gas volumes. The $374.1 million decrease in energy services revenue and the related decrease in purchased natural gas sold were due primarily to decreased energy marketing volumes resulting from the sale of the vast majority of the Company's energy marketing operations in the third quarter of 2001. Natural Gas and Oil Production Natural gas and oil production earnings decreased largely due to lower realized natural gas and oil prices, which were 28 percent and 7 percent lower than the prior year, respectively, along with lower oil production of 4 percent; partially offset by higher natural gas production of 19 percent, largely from operated properties in the Rocky Mountain area. Also adding to the earnings decline were increased depreciation, depletion and amortization expense due to higher natural gas production volumes and higher rates; increased operation and maintenance expenses, mainly higher lease operating expenses resulting from the expansion of coalbed natural gas production; and lower sales volumes of inventoried natural gas. Partially offsetting the earnings decline were the effects of the previously discussed 2002 compromise agreement gain. Construction Materials and Mining Earnings for the construction materials and mining business increased as a result of earnings from businesses acquired since the comparable prior period; higher aggregate, asphalt and cement sales volumes; increased construction revenues, largely the result of several large projects mainly in California and Oregon; and lower asphalt costs. Partially offsetting the increase in earnings were the 2001 gain from the sale of the Company's coal operations, as previously discussed, as well as earnings from four months of coal operations included in 2001 earnings. Higher selling, general and administrative costs, mainly due to higher computer support, insurance and payroll costs; and higher depreciation, depletion and amortization expense due to higher sales volumes; partially offset by the discontinuance of the amortization of goodwill in 2002 ($1.7 million after tax in 2001), also added to the partial offset in earnings. Independent Power Production and Other Earnings at the independent power production and other businesses totaled $959,000. The majority of these earnings came from the newly acquired 213-megawatt natural gas-fired electric generating facilities in Colorado. The Brazilian operations also contributed to earnings. The Company's 49 percent share of the gain of $13.6 million (after tax) from an embedded derivative in the electric power contract and margins at the Brazil facilities were largely offset by the Company's 49 percent share of the foreign currency losses of $9.4 million (after tax) resulting from devaluation of the Brazilian real and net interest expense of $3.6 million (after tax). Risk Factors and Cautionary Statements that May Affect Future Results The Company is including the following factors and cautionary statements in this Form 10-K to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Prospective Information. All these subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these factors and cautionary statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management's examination of historical operating trends, data contained in the Company's records and other data available from third parties. Nonetheless, the Company's expectations, beliefs or projections may not be achieved or accomplished. Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward- looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward- looking statement. Following are some specific factors that should be considered for a better understanding of the Company's financial condition. These factors and the other matters discussed herein are important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this document. Economic Risks The Company's natural gas and oil production business is dependent on factors, including commodity prices, which cannot be predicted or controlled. These factors include: price fluctuations in natural gas and crude oil prices; availability of economic supplies of natural gas; drilling successes in natural gas and oil operations; the ability to contract for or to secure necessary drilling rig contracts and to retain employees to drill for and develop reserves; the ability to acquire natural gas and oil properties; and other risks incidental to the operations of natural gas and oil wells. The current soft economic environment and the depressed telecommunications market may have a general negative impact on the Company's future revenues and may result in a goodwill impairment for Innovatum, Inc. (Innovatum), an indirect wholly owned subsidiary of the Company. In response to the ongoing war against terrorism by the United States and the bankruptcy of several large energy and telecommunications companies and other large enterprises, the financial markets have been volatile. A soft economy could negatively affect the level of public and private expenditures on projects and the timing of these projects which, in turn, would negatively affect the demand for the Company's products and services. Innovatum, which specializes in cable and pipeline magnetization and locating, is subject to the economic conditions within the telecommunications and energy industries. Innovatum has also developed a hand-held locating device that can detect both magnetic and plastic materials. Innovatum could face a future goodwill impairment if there is a continued downturn in the telecommunications and energy industries or if it cannot find a successful market for the hand-held locating device. At December 31, 2003, the goodwill amount at Innovatum was approximately $8.3 million. The determination of whether an impairment will occur is dependent on a number of factors, including the level of spending in the telecommunications and energy industries, the success of the hand-held locating device at Innovatum, rapid changes in technology, competitors and potential new customers. The Company relies on financing sources and capital markets. If the Company were unable to access financing in the future, the Company's ability to execute its business plans, make capital expenditures or pursue acquisitions that the Company may otherwise rely on for future growth could be impaired. The Company relies on access to both short-term borrowings, including the issuance of commercial paper, and long-term capital markets as a source of liquidity for capital requirements not satisfied by the cash flow from operations. If the Company is not able to access capital at competitive rates, the ability to implement its business plans may be adversely affected. Market disruptions or a downgrade of the Company's credit ratings may increase the cost of borrowing or adversely affect its ability to access one or more financial markets. Such disruptions could include: - A severe prolonged economic downturn - The bankruptcy of unrelated industry leaders in the same line of business - Capital market conditions generally - Volatility in commodity prices - Terrorist attacks - Global events Environmental and Regulatory Risks Some of the Company's operations are subject to extensive environmental laws and regulations that may increase its costs of operations, impact or limit its business plans, or expose the Company to environmental liabilities. One of the Company's subsidiaries is subject to litigation in connection with its coalbed natural gas development activities. The Company is subject to extensive environmental laws and regulations affecting many aspects of its present and future operations including air quality, water quality, waste management and other environmental considerations. These laws and regulations can result in increased capital, operating and other costs, as a result of compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to power plant emissions and coalbed natural gas development. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Public officials and entities, as well as private individuals and organizations, may seek to enforce applicable environmental laws and regulations. The Company cannot predict the outcome (financial or operational) of any related litigation that may arise. Existing environmental regulations may be revised and new regulations seeking to protect the environment may be adopted or become applicable to the Company. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material effect on the Company's results of operations. Fidelity has been named as a defendant in, and/or certain of its operations are the subject of, 11 lawsuits filed in connection with its coalbed natural gas development in the Powder River Basin in Montana and Wyoming. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could have a material effect on Fidelity's existing coalbed natural gas operations and/or the future development of its coalbed natural gas properties. The Company is subject to extensive government regulations that may have a negative impact on its business and its results of operations. The Company is subject to regulation by federal, state and local regulatory agencies with respect to, among other things, allowed rates of return, financings, industry rate structures, and recovery of purchased power and purchased gas costs. These governmental regulations significantly influence the Company's operating environment and may affect its ability to recover costs from its customers. The Company is unable to predict the impact on operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on the Company's results of operations. Risks Relating to the Company's Independent Power Production Business The operation of power generation facilities involves many risks, including start-up risks, breakdown or failure of equipment, competition, inability to obtain required governmental permits and approvals and inability to negotiate acceptable acquisition, construction, fuel supply, off-take, transmission or other material agreements, as well as the risk of performance below expected levels of output or efficiency. The Company has begun construction of a 113-megawatt coal- fired development project in Hardin, Montana. Based on demand and power pricing in the Northwest, the plant is being built on a merchant basis. Unanticipated events could delay completion of construction, start-up and/or operation of the project. Changes in the market price for power from the Company's projections could also negatively impact earnings to be derived from the project. Risks Relating to Foreign Operations The value of the Company's investment in foreign operations may diminish due to political, regulatory and economic conditions and changes in currency exchange rates in countries where the Company does business. The Company is subject to political, regulatory and economic conditions and changes in currency exchange rates in foreign countries where the Company does business. Significant changes in the political, regulatory or economic environment in these countries could negatively affect the value of the Company's investments located in these countries. Also, since the Company is unable to predict the fluctuations in the foreign currency exchange rates, these fluctuations may have an adverse impact on the Company's results of operations. The Company's 49 percent equity method investment in a 220- megawatt natural gas-fired electric generation project in Brazil includes a power purchase agreement that contains an embedded derivative. This embedded derivative derives its value from an annual adjustment factor that largely indexes the contract capacity payments to the U.S. dollar. In addition, from time to time, other derivative instruments may be utilized. The valuation of these financial instruments, including the embedded derivative, can involve judgments, uncertainties and the use of estimates. As a result, changes in the underlying assumptions could affect the reported fair value of these instruments. These instruments could recognize financial losses as a result of volatility in the underlying fair values, or if a counterparty fails to perform. Other Risks Competition is increasing in all of the Company's businesses. All of the Company's businesses are subject to increased competition. The independent power industry includes numerous strong and capable competitors, many of which have greater resources and more experience in the operation, acquisition and development of power generation facilities. Utility services' competition is based primarily on price and reputation for quality, safety and reliability. The construction materials products are marketed under highly competitive conditions and are subject to such competitive forces as price, service, delivery time and proximity to the customer. The electric utility and natural gas industries are also experiencing increased competitive pressures as a result of consumer demands, technological advances, deregulation, greater availability of natural gas-fired generation and other factors. Pipeline and energy services competes with several pipelines for access to natural gas supplies and gathering, transportation and storage business. The natural gas and oil production business is subject to competition in the acquisition and development of natural gas and oil properties as well as in the sale of its production output. Weather conditions can adversely affect the Company's operations and revenues. The Company's results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas, affect the wind-powered operation at the independent power production business, affect the price of energy commodities, affect the ability to perform services at the utility services and construction materials and mining businesses and affect ongoing operation and maintenance activities for the pipeline and energy services and natural gas and oil production businesses. In addition, severe weather can be destructive, causing outages and/or property damage, which could require additional costs to be incurred. As a result, adverse weather conditions could negatively affect the Company's results of operations and financial condition. Prospective Information The following information includes highlights of the key growth strategies, projections and certain assumptions for the Company and its subsidiaries over the next few years and other matters for each of the Company's businesses. Many of these highlighted points are forward-looking statements. There is no assurance that the Company's projections, including estimates for growth and increases in revenues and earnings, will in fact be achieved. Reference is made to assumptions contained in this section, as well as the various important factors listed under the heading Risk Factors and Cautionary Statements that May Affect Future Results, and other factors that are listed in Part I. Changes in such assumptions and factors could cause actual future results to differ materially from targeted growth, revenue and earnings projections. MDU Resources Group, Inc. - Earnings per common share for 2004, diluted, are projected in the range of $1.55 to $1.68. - The Company expects the percentage of 2004 earnings per common share, diluted, by quarter to be in the following approximate ranges: - First quarter - 13 percent to 18 percent - Second quarter - 19 percent to 24 percent - Third quarter - 35 percent to 40 percent - Fourth quarter - 23 percent to 28 percent - The Company's long-term compound annual growth goals on earnings per share from operations are in the range of 6 percent to 9 percent. - The Company will consider issuing equity from time to time to keep debt at the nonregulated businesses at no more than 40 percent of total capitalization. - The Company has formed an alliance with several electric cooperatives in the region to evaluate potential utility opportunities presented by the bankruptcy of NorthWestern. NorthWestern filed for Chapter 11 bankruptcy protection on September 14, 2003. Electric - 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 franchises expire, Montana-Dakota may face increasing competition in its service areas, particularly its service to smaller towns, from rural electric cooperatives. Montana-Dakota intends to protect its service area and seek renewal of all expiring franchises and will continue to take steps to effectively operate in an increasingly competitive environment. - Expected returns in 2004 are anticipated to be generally consistent with authorized levels. - Montana-Dakota filed an application with the NDPSC seeking an increase in electric retail rates of $7.8 million annually or 9.1 percent above current rates. On December 18, 2003, the NDPSC approved a Settlement Agreement for an increase of $1.0 million annually and a sharing mechanism between Montana-Dakota and retail customers of wholesale electric sales margins. For further information on the electric rate increase application, see Item 8 -- Financial Statements and Supplementary Data - Note 18. - Regulatory approval has been received from the NDPSC and the SDPUC on the Company's plans to purchase energy from a 20- megawatt wind energy farm in North Dakota. The contract provides for this wind energy farm to be on-line by early to mid 2004. - The Company continues to evaluate potential needs for future generation. The Company expects to build or acquire an additional 175-megawatts to 200-megawatts of capacity over the next 10 years to replace expiring contracts and meet system growth requirements. The Company is working with the state of North Dakota to determine the feasibility of constructing a lignite-fired power plant in western North Dakota. The Company also announced its involvement in a coalition with four other utilities to study the feasibility of building a coal-based electric generating facility possibly combined with a wind energy facility at potential sites in North Dakota, South Dakota and Iowa. The costs of building and/or acquiring the additional generating capacity needed by the utility are expected to be recovered in rates. Natural gas distribution - Montana-Dakota and Great Plains have obtained and hold valid and existing franchises authorizing them to conduct their natural gas operations in all of the municipalities they serve where such franchises are required. As franchises expire, Montana-Dakota and Great Plains may face increasing competition in their service areas. Montana-Dakota and Great Plains intend to protect their service areas and seek renewal of all expiring franchises and will continue to take steps to effectively operate in an increasingly competitive environment. - Annual natural gas throughput for 2004 is expected to be approximately 52 million decatherms. - The Company expects to seek natural gas rate increases from time to time to offset higher expected operating costs. - Montana-Dakota filed an application with the SDPUC seeking an increase in natural gas retail rates of $2.2 million annually or 5.8 percent above current rates. On December 2, 2003, the SDPUC approved a Settlement Stipulation for an increase of $1.3 million annually. Great Plains filed an application with the MPUC seeking an increase in natural gas retail rates of $1.6 million annually or 6.9 percent above current rates. On October 9, 2003, the MPUC issued a Final Order authorizing an increase of $1.1 million annually. For further information on the natural gas rate increase applications, see Item 8 -- Financial Statements and Supplementary Data - Note 18. Utility services - Revenues for this segment are expected to be in the range of $440 million to $490 million in 2004. - This segment anticipates margins to increase in 2004 as compared to 2003 levels. Pipeline and energy services - In 2004, total natural gas throughput is expected to increase approximately 25 percent to 30 percent over 2003 levels largely due to the 253-mile Grasslands Pipeline, which began providing natural gas transmission service on December 23, 2003. - Firm capacity for the Grasslands Pipeline is currently 90 million cubic feet per day with expansion possible to 200 million cubic feet per day. - Transportation rates are expected to decline in 2004 from 2003 levels due to the estimated effects of a FERC rate order received in July 2003. - Innovatum could face a future goodwill impairment based on certain economic conditions, as previously discussed in Risk Factors and Cautionary Statements that May Affect Future Results. Innovatum recently developed a hand-held locating device that can detect both magnetic and plastic materials. One of the possible uses for this product would be in the detection of unexploded ordnance. Innovatum is in the preliminary stages of working with and demonstrating the device to a Department of Defense contractor and has met with individuals from the Department of Defense. Natural gas and oil production - In 2004, this segment expects a combined production increase of approximately 10 percent over 2003 levels. Currently, this segment's gross operated natural gas production is approximately 140,000 Mcf to 150,000 Mcf per day. - This segment continues to expand its operated production. Natural gas production from operated properties was 74 percent and 69 percent of total natural gas production for the years ended December 31, 2003 and 2002, respectively. - This segment expects to participate in drilling more than 400 wells in 2004. - At December 31, 2003, this segment had 118 gross wells in the process of drilling or under evaluation, 113 of which were development wells and five of which were exploratory wells. This segment expects to complete drilling and testing the majority of these wells within the next 12 months. - Natural gas prices in the Rocky Mountain region for February through December 2004 reflected in the Company's 2004 earnings guidance are in the range of $3.25 to $3.75 per Mcf. The Company's estimates for natural gas prices on the NYMEX for February through December 2004, reflected in the Company's 2004 earnings guidance, are in the range of $4.00 to $4.50 per Mcf. During 2003, more than two-thirds of this segment's natural gas production was priced using Rocky Mountain or other non-NYMEX prices. - NYMEX crude oil prices for January through December 2004, reflected in the Company's 2004 earnings guidance, are in the range of $26 to $30 per barrel. - The Company has hedged a portion of its 2004 estimated annual natural gas production. The Company has entered into agreements representing approximately 30 percent to 35 percent of 2004 estimated annual natural gas production. The agreements are at various indices and range from a low CIG index of $3.75 to a high CIG index of $5.48 per Mcf. - The Company has hedged a portion of its 2004 oil production. The Company has entered into agreements at NYMEX prices with a low of $28.84 and a high of $30.28, representing approximately 30 percent to 35 percent of 2004 estimated annual oil production. - The Company has hedged less than 5 percent of its 2005 estimated annual natural gas production and will continue to evaluate additional opportunities. Construction materials and mining - Aggregate volumes in 2004 are expected to be comparable to 2003 levels, while ready-mixed concrete and asphalt volumes are expected to increase over 2003 levels. - Revenues in 2004 are expected to increase by approximately 5 percent to 10 percent over 2003 levels. - Knife River expects that the replacement funding legislation for the Transportation Equity Act for the 21st Century (TEA-21) will be at funding levels equal to or higher than the funding under TEA-21. - On February 6, 2004, this segment acquired a ready-mixed concrete producer and concrete and asphalt paving company in Iowa and two aggregate mining and production companies in Minnesota. The companies have combined annual revenues of approximately $90 million. Independent power production and other - Earnings projections in 2004 for independent power production and other operations include the estimated results from the wind-powered electric generating facility in California, the natural gas-fired electric generating facility in Colorado, and the Company's 49-percent ownership in a 220-megawatt natural gas-fired electric generating facility in Brazil. Earnings are expected to be in the range of $18 million to $23 million in 2004. - The Company has begun construction of a 113-megawatt coal- fired development project in Hardin, Montana, as previously discussed in Risk Factors and Cautionary Statements that May Affect Future Results. Based on demand and power pricing in the Northwest, the plant is being built on a merchant basis. Efforts will continue towards securing a contract for the off-take of the plant. The Company is optimistic that this plant will be under contract by the time of plant completion. The projected on-line date for this plant is late 2005. New Accounting Standards In 2003, the Company adopted the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," and began expensing the fair market value of stock options for all awards granted on or after January 1, 2003. Compensation expense recognized for awards granted on or after January 1, 2003, for the year ended December 31, 2003, was $41,000 (after tax). In June 2001, the Financial Accounting Standards Board (FASB) approved SFAS No. 143. Upon adoption of SFAS No. 143, the Company recorded an additional discounted liability of $22.5 million and a regulatory asset of $493,000, increased net property, plant and equipment by $9.6 million and recognized a one-time cumulative effect charge of $7.6 million (net of deferred income tax benefits of $4.8 million). In April 2002, the FASB approved SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." The adoption of SFAS No. 145 did not have a material effect on the Company's financial position or results of operations. In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). The Company is applying the initial recognition and initial measurement provisions of FIN 45 to guarantees issued or modified after December 31, 2002. In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not have a material effect on the Company's financial position or results of operations. In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company will apply SFAS No. 150 to any financial instruments entered into or modified after May 31, 2003. Beginning in 2003, the Company reported its preferred stock subject to mandatory redemption as a liability in accordance with SFAS No. 150. The transition to SFAS No. 150 did not have a material effect on the Company's financial position or results of operations. In December 2003, the FASB issued FASB Interpretation No. 46 (revised 2003), "Consolidation of Variable Interest Entities" (FIN 46 (revised)), which revised FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46). FIN 46 (revised) shall be applied to all entities subject to FIN 46 (revised) no later than the end of the first reporting period that ends after March 15, 2004. However, an entity that applied FIN 46 to an entity prior to the effective date of FIN 46 (revised) shall either continue to apply FIN 46 until the effective date of FIN 46 (revised) or apply FIN 46 (revised) at an earlier date. The adoption of FIN 46 did not have a material effect on the Company's financial position or results of operations. The Company will continue to apply FIN 46 until the effective date of FIN 46 (revised). In December 2003, the FASB issued SFAS No. 132 (revised 2003), "Employers' Disclosures about Pension and Other Postretirement Benefits." SFAS No. 132 (revised 2003) is effective for financial statements with fiscal years ending after December 15, 2003. The Company applied SFAS No. 132 (revised 2003) to its consolidated financial statements issued after December 15, 2003. In January 2004, the FASB issued FASB Staff Position No. FAS 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." FASB Staff Position No. FAS 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (2003 Medicare Act). The Company provides prescription drug benefits to certain eligible employees and has elected the one-time deferral of accounting for the effects of the 2003 Medicare Act. The Company intends to analyze the 2003 Medicare Act, along with the authoritative guidance, when issued, to determine if its benefit plans need to be amended and how to record the effects of the 2003 Medicare Act. For further information on SFAS No. 123, SFAS No. 143, SFAS No. 145, FIN 45, SFAS No. 149, SFAS No. 150, FIN 46 (revised), SFAS No. 132 (revised 2003) and FASB Staff Position No. FAS 106- 1, see Item 8 -- Financial Statements and Supplementary Data - Note 1. Critical Accounting Policies Involving Significant Estimates The Company has prepared its financial statements in conformity with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company's significant accounting policies are discussed in Item 8 -- Financial Statements and Supplementary Data - Note 1. Estimates are used for items such as impairment testing of long-lived assets, goodwill and natural gas and oil properties; fair values of acquired assets and liabilities under the purchase method of accounting; natural gas and oil reserves; property depreciable lives; tax provisions; uncollectible accounts; environmental and other loss contingencies; accumulated provision for revenues subject to refund; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; the valuation of stock-based compensation; and the fair value of derivative instruments, including the fair value of an embedded derivative in a power purchase agreement related to an equity method investment in Brazil, as discussed in Item 8 -- Financial Statements and Supplementary Data - Note 2. The Company's critical accounting policies are subject to judgments and uncertainties that affect the application of such policies. As discussed below, the Company's financial position or results of operations may be materially different when reported under different conditions or when using different assumptions in the application of such policies. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. The following critical accounting policies involve significant judgments and estimates. Impairment of long-lived assets and intangibles The Company reviews the carrying values of its long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstances indicate that such carrying values may not be recoverable and annually for goodwill as required by SFAS No. 142, "Goodwill and Other Intangible Assets." Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows could negatively affect the fair value of the Company's assets and result in an impairment charge. If an impairment indicator exists for tangible and intangible assets, excluding goodwill, the asset group held and used is tested for recoverability by comparing the carrying value to its fair value, based on an estimate of undiscounted future cash flows attributable to the assets. In the case of goodwill, the first step, used to identify a potential impairment, compares the fair value of the reporting unit using discounted cash flows, with its carrying amount, including goodwill. The second step, used to measure the amount of the impairment loss if step one indicates a potential impairment, compares the implied fair value of the reporting unit goodwill with the carrying amount of goodwill. Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties. The Company uses critical estimates and assumptions when testing assets for impairment, including present value techniques based on estimates of cash flows, quoted market prices or valuations by third parties, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques. There is risk involved when determining the fair value of assets, tangible and intangible, as there may be unforeseen events and changes in circumstances and market conditions and changes in estimates of future cash flows. The Company believes its estimates used in calculating the fair value of long-lived assets, including goodwill and identifiable intangibles, are reasonable based on the information that is known at the point in time the estimates are made. In addition, goodwill impairment testing is performed annually in accordance with SFAS No. 142 and no impairment loss has been recorded subsequent to the adoption of SFAS No. 141, "Business Combinations" and SFAS No. 142. Natural gas and oil properties The Company uses the full-cost method of accounting for its natural gas and oil production activities. 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 based on single point-in-time spot market prices, as mandated under the rules of the Securities and Exchange Commission, and the lower of cost or fair value of unproved properties. Judgments and assumptions are made when estimating and valuing reserves. There is risk that sustained downward movements in natural gas and oil prices and changes in estimates of reserve quantities could result in a future write-down of the Company's natural gas and oil properties. Estimates of reserves are arrived at using actual historical wellhead production trends and/or standard reservoir engineering methods utilizing all available engineering and geologic data derived from well tests. Other factors used in the reserve estimates are current natural gas and oil prices, current estimates of well operating and future development costs, and the interest owned by the Company in the well. These estimates are refined as new information becomes available. Historically, the Company has not had any material revisions to its reserve estimates. As a result, the Company has not changed its practice in estimating reserves and does not anticipate changing its methodologies in the future. Revenue recognition Revenue is recognized when the earnings process is complete, as evidenced by an agreement between the customer and the Company, when delivery has occurred or services have been rendered, when the fee is fixed or determinable and when collection is probable. The recognition of revenue in conformity with accounting principles generally accepted in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of revenue. Critical estimates related to the recognition of revenue include the accumulated provision for revenues subject to refund and costs on construction contracts under the percentage-of- completion method. Estimates for revenues subject to refund are established initially for each regulatory rate proceeding and are subject to change depending on the applicable regulatory agency's (Agency) approval of final rates. These estimates are based on the Company's analysis of its as-filed application compared to previous Agency decisions in prior rate filings by the Company and other regulated companies. The Company periodically reviews the status of its outstanding regulatory proceedings and reserve assumptions and may from time to time change its reserve estimates subject to known developments as the regulatory proceedings move through the regulatory review process. The accuracy of the estimates is ultimately determined when the Agency issues its final ruling on each regulatory proceeding for which revenues were subject to refund. Estimates have changed from time to time as additional information has become available as to what the ultimate outcome may be and will likely continue to change in the future as new information becomes available on each outstanding regulatory proceeding that is subject to refund. The Company recognizes construction contract revenue from fixed price and modified fixed price construction contracts at its construction businesses using the percentage-of-completion method, measured by the percentage of costs incurred to date to estimated total costs for each contract. This method depends largely on the ability to make reasonably dependable estimates related to the extent of progress toward completion of the contract, contract revenues and contract costs. There are risks involved when making these estimates as contract prices are generally set before the work is performed, which means every project could contain significant unknown risks such as volatile labor and material costs, weather delays, adverse project site conditions, unforeseen actions by regulatory agencies, performance by subcontractors, job management and relations with project owners. Several factors are evaluated in determining the bid price for contract work. These include, but are not limited to, the complexities of the job, past history performing similar types of work, seasonal weather patterns, competition and market conditions, job site conditions, work force safety, reputation of the project owner, availability of labor and materials, project location and project completion dates. As a project commences, estimates are continually monitored and revised as information becomes available and actual costs and conditions surrounding the job become known. The Company believes its estimates surrounding percentage-of- completion accounting are reasonable based on the information that is known at the point in time the estimates are made. The Company has contract administration, accounting and management control systems in place that allow its estimates to be updated and monitored on a regular basis. Because of the many factors that are evaluated in determining bid prices, it is inherent that the Company's estimates have changed in the past and will continually change in the future as new information becomes available for each job. Purchase accounting The Company accounts for its acquisitions under the purchase method of accounting and, accordingly, the acquired assets and liabilities assumed are recorded at their respective fair values. The excess of the purchase price over the fair value of the assets acquired and liabilities assumed is recorded as goodwill. The recorded values of assets and liabilities are based on third- party estimates and valuations when available. The remaining values are based on management's judgments and estimates, and, accordingly, the Company's financial position or results of operations may be affected by changes in estimates and judgments. Acquired assets and liabilities assumed by the Company that are subject to critical estimates include property, plant and equipment (including owned aggregate reserve deposits) and intangible assets. The fair value of owned recoverable aggregate reserve deposits are determined using qualified internal personnel as well as geologists. Reserve estimates are calculated based on the best available data. This data is collected from drill holes and other subsurface investigations as well as investigations of surface features such as mine highwalls and other exposures of the aggregate reserves. Mine plans, production history and geologic data are also used to estimate reserve quantities. Value is assigned to the aggregate reserves based on a review of market royalty rates, expected cash flows and the number of years of recoverable aggregate reserves at owned aggregate sites. The fair value of property, plant and equipment is based on a valuation performed either by qualified internal personnel and/or outside appraisers. Fair values assigned to plant and equipment are based on several factors including the age and condition of the equipment, maintenance records of the equipment and auction values for equipment with similar characteristics at the time of purchase. Intangible assets are identified and valued using the guidelines of SFAS No. 141. The fair value of intangible assets is based on estimates including royalty rates, lease terms and other discernible factors for acquired leasehold rights, and estimated cash flows. While the allocation of the purchase price of an acquisition is subject to a high level of judgment and uncertainty, the Company does not expect the estimates to vary significantly once an acquisition has been completed. The Company believes its estimates have been reasonable in the past as there have been no significant valuation adjustments subsequent to the final allocation of the purchase price to the acquired assets and liabilities. In addition, goodwill impairment testing is performed annually in accordance with SFAS No. 142. No impairment loss has been recorded subsequent to the adoption of SFAS No. 141 and SFAS No. 142, as previously discussed. Asset retirement obligations SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The Company has recorded obligations related to the plugging and abandonment of natural gas and oil wells, decommissioning of certain electric generating facilities, reclamation of certain aggregate properties and certain other obligations associated with leased properties. The liability for future asset retirement obligations bears the risk of change as many factors go into the development of the estimate of these obligations and the possibility that over time these factors can and will change. Factors used in the estimation of future asset retirement obligations include estimates of current retirement costs, future inflation factors, life of the asset and discount rates. These factors determine both a present value of the retirement liability and the accretion to the retirement liability in subsequent years. Long-lived assets are reviewed to determine if a legal retirement obligation exists. If a legal retirement obligation exists, a determination of the liability is made if a reasonable estimate of the present value of the obligation can be made. The present value of the retirement obligation is calculated by inflating current estimated retirement costs of the long-lived asset over its expected life to determine the expected future cost and then discounting the expected future cost back to the present value using a discount rate equal to the credit-adjusted risk-free interest rate in effect when the liability was initially recognized. These estimates and assumptions are subject to a number of variables and are expected to change in the future. Estimates and assumptions will change as the estimated useful lives of the assets change, the current estimated retirement costs change, new legal retirement obligations occur and/or as existing legal asset retirement obligations, for which a reasonable estimate of fair value could not initially be made because of uncertainty, become less uncertain and a reasonable estimate of the future liability can be made. Pension and other postretirement benefits The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to these plans. Costs of providing pension and other postretirement benefits bear the risk of change, as they are dependent upon numerous factors based on assumptions of future conditions. The Company makes various assumptions when determining plan costs, including the current discount rates and the expected long- term return on plan assets, the rate of compensation increases and healthcare cost trend rates. In selecting the expected long- term return on plan assets, which is considered to be one of the key variables in determining benefit expense or income, the Company considers both current market conditions and expected future market trends, including changes in interest rates and equity and bond market performance. Another key variable in determining benefit expense or income is the discount rate. In selecting the discount rate, the Company uses the yield of a fixed-income debt security, which has a rating of "Aa" or higher published by a recognized rating agency, as well as other factors, as a basis. The pension and other postretirement benefit plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity and bond market returns as well as changes in general interest rates may result in increased or decreased pension and other postretirement benefit costs in the future. Management estimates the rate of compensation increase based on long-term assumed wage increases and the healthcare cost trend rates are determined by historical and future trends. The Company believes the estimates made for its pension and other postretirement benefits are reasonable based on the information that is known at the point in time the estimates are made. These estimates and assumptions are subject to a number of variables and are expected to change in the future. Estimates and assumptions will be affected by changes in the discount rate, the expected long-term return on plan assets, the rate of compensation increase and healthcare cost trend rates. The Company plans to continue to use its current methodologies to determine plan costs. Liquidity and Capital Commitments Cash flows Operating activities -- Cash flows provided by operating activities in 2003 increased $92.1 million compared to 2002, primarily the result of higher deferred income taxes of $33.8 million due in part to additional tax depreciation allowed in 2003. Also adding to the increase in cash flows provided by operating activities were higher depreciation, depletion and amortization expense of $30.4 million, resulting largely from increased property, plant and equipment balances and higher mineral production volumes, and an increase in cash from net income of $26.9 million. In 2002, cash flows from operating activities decreased $22.2 million compared to 2001, largely the result of a decrease in cash from working capital items of $58.4 million. The working capital decrease was primarily due to lower natural gas prices compared to 2001. Higher depreciation, depletion and amortization expense of $18.0 million, resulting largely from increased property, plant and equipment balances, along with an increase in other noncurrent changes of $15.7 million, partially offset the decrease in cash flows from operating activities. Investing activities -- Cash flows used in investing activities in 2003 increased $67.1 million compared to 2002, the result of an increase in net capital expenditures (capital expenditures; acquisitions, net of cash acquired; and net proceeds from the sale or disposition of property) of $78.1 million, partially offset by an increase in cash flows from investments of $7.2 million and proceeds from notes receivable of $3.8 million. Net capital expenditures exclude the noncash transactions related to acquisitions, including the issuance of the Company's equity securities. The noncash transactions were $42.4 million and $47.2 million for the years ended December 31, 2003 and 2002, respectively. In 2002, cash flows used in investing activities increased $6.2 million compared to 2001, the result of an increase in net capital expenditures of $22.6 million and an increase in investments of $7.4 million, partially offset by a decrease in notes receivable of $23.8 million. Net capital expenditures exclude the noncash transactions related to acquisitions, including the issuance of the Company's equity securities. The noncash transactions were $47.2 million and $57.4 million for the years ended December 31, 2002 and 2001, respectively. Financing activities -- Cash flows provided by financing activities in 2003 decreased $31.9 million compared to 2002, the result of a decrease of proceeds from issuance of common stock of $54.6 million, a net decrease in short-term borrowings of $40.0 million and an increase in the repayment of long-term debt of $23.2 million. The increase in the issuance of long-term debt of $90.8 million partially offset the decrease in cash provided by financing activities. In 2002, cash flows provided by financing activities increased $48.8 million compared to 2001. This increase was primarily the result of the decrease of the repayment of long-term debt of $32.5 million and the net increase of short-term borrowings of $28.0 million, partially offset by the decrease in proceeds from issuance of common stock of $12.0 million. Defined benefit pension plans The Company has qualified noncontributory defined benefit pension plans (Pension Plans) for certain employees. Plan assets consist of investments in equity and fixed income securities. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to the Pension Plans. Actuarial assumptions include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as determined by the Company within certain guidelines. At December 31, 2003, certain Pension Plans' accumulated benefit obligations exceeded these plans' assets by approximately $4.3 million. Pretax pension expense (income) reflected in the years ended December 31, 2003, 2002 and 2001 was $153,000, ($2.4) million and ($4.4) million, respectively. The Company's pension expense is currently projected to be approximately $4.0 million to $5.0 million in 2004. A reduction in the Company's assumed discount rate for Pension Plans along with declines in the equity markets experienced in 2002 and 2001 have combined to largely produce the increase in these costs. Funding for the Pension Plans is actuarially determined. The minimum required contributions for 2003, 2002 and 2001 were approximately $1.6 million, $1.2 million and $442,000, respectively. For further information on the Company's Pension Plans, see Item 8 -- Financial Statements and Supplementary Data - Note 16. Capital expenditures The Company's capital expenditures (in millions) for 2001 through 2003 and as anticipated for 2004 through 2006 are summarized in the following table, which also includes the Company's capital needs for the retirement of maturing long-term debt. Actual Estimated* 2001 2002 2003 Capital expenditures: 2004 2005 2006 $ 14.4 $ 27.8 $ 28.5 Electric $ 23.3 $ 46.3 $123.0 14.7 11.0 15.7 Natural gas distribution 13.5 16.8 16.2 70.2 17.3 7.8 Utility services 9.5 10.3 10.9 Pipeline and energy 51.0 21.5 93.0 services 38.3 29.7 32.8 Natural gas and oil 118.7 136.4 101.7 production 139.9 138.7 123.2 Construction materials 170.6 106.9 128.5 and mining 90.0 82.4 80.7 Independent power --- 95.7 112.8 production and other 66.1 80.9 50.7 439.6 416.6 488.0 380.6 405.1 437.5 Net proceeds from sale or (51.6) (16.2) (14.4) disposition of property (10.7) (3.0) (1.6) 388.0 400.4 473.6 Net capital expenditures 369.9 402.1 435.9 Retirement of 115.2 82.6 105.7 long-term debt 27.6 70.9 173.2 $503.2 $483.0 $579.3 $397.5 $473.0 $609.1 _________________________________ *The estimated 2004 through 2006 capital expenditures reflected in the above table include potential future acquisitions. The Company continues to evaluate potential future acquisitions; however, these acquisitions are dependent upon the availability of economic opportunities and, as a result, actual acquisitions and capital expenditures may vary significantly from the above estimates. Capital expenditures for 2003, 2002 and 2001, related to acquisitions, in the preceding table include the following noncash transactions: issuance of the Company's equity securities of $42.4 million in 2003, $47.2 million in 2002 and $57.4 million in 2001. In 2003, the Company acquired a number of businesses, none of which was individually material, including construction materials and mining businesses in Montana, North Dakota and Texas and a wind-powered electric generating facility in California. The total purchase consideration for these businesses and adjustments with respect to certain other acquisitions acquired in 2002, including the Company's common stock and cash, was $175.0 million. Pro forma financial amounts reflecting the effects of the above acquisitions are not presented, as such acquisitions were not material to the Company's financial position or results of operations. The 2003 capital expenditures, including those for the previously mentioned acquisitions and retirements of long-term debt, were met from internal sources, the issuance of long-term debt and the Company's equity securities. Estimated capital expenditures for the years 2004 through 2006 include those for: - Potential future acquisitions - System upgrades - Routine replacements - Service extensions - Routine equipment maintenance and replacements - Land and building improvements - Pipeline and gathering expansion projects - The further enhancement of natural gas and oil production and reserve growth - Power generation opportunities, including the construction or acquisition of an additional 175-megawatts to 200-megawatts of capacity over the next 10 years and certain construction costs for a 113-megawatt coal-fired development project, as previously discussed - Other growth opportunities The Company continues to evaluate potential future acquisitions and other growth opportunities; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimates in the preceding table. It is anticipated that all of the funds required for capital expenditures and retirements of long-term debt for the years 2004 through 2006 will be met from various sources. These sources include internally generated funds; commercial paper credit facilities at Centennial and MDU Resources Group, Inc., as described below; and through the issuance of long-term debt and the Company's equity securities. Capital resources Certain debt instruments of the Company and its subsidiaries, including those discussed below, contain restrictive covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2003. MDU Resources Group, Inc. The Company has a revolving credit agreement with various banks totaling $90 million at December 31, 2003. There were no amounts outstanding under the credit agreement at December 31, 2003. The credit agreement supports the Company's $75 million commercial paper program. Under the Company's commercial paper program, $40.0 million was outstanding at December 31, 2003. The commercial paper borrowings are classified as long-term debt as the Company intends to refinance these borrowings on a long-term basis through continued commercial paper borrowings and as further supported by the credit agreement, which expires on July 18, 2006. The Company's goal is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. If the Company were to experience a minor downgrade of its credit ratings, it would not anticipate any change in its ability to access the capital markets. However, in such event, the Company would expect a nominal basis point increase in overall interest rates with respect to its cost of borrowings. If the Company were to experience a significant downgrade of its credit ratings, which it does not currently anticipate, it may need to borrow under its credit agreement. To the extent the Company needs to borrow under its credit agreement, it would be expected to incur increased annualized interest expense on its variable rate debt of approximately $60,000 (after tax) based on December 31, 2003, variable rate borrowings. Based on the Company's overall interest rate exposure at December 31, 2003, this change would not have a material effect on the Company's results of operations or cash flows. Prior to the maturity of the credit agreement, the Company plans to negotiate the extension or replacement of this agreement that provides credit support to access the capital markets. In the event the Company was unable to successfully negotiate the credit agreement, or in the event the fees on this facility became too expensive, which it does not currently anticipate, the Company would seek alternative funding. One source of alternative funding might involve the securitization of certain Company assets. In order to borrow under the Company's credit agreement, the Company must be in compliance with the applicable covenants and certain other conditions. The significant covenants include maximum leverage ratios, minimum interest coverage ratio, limitation on sale of assets and limitation on investments. The Company was in compliance with these covenants and met the required conditions at December 31, 2003. In the event the Company does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued, as previously described. There are no credit facilities that contain cross-default provisions between the Company and any of its subsidiaries. On December 23, 2003, the Company issued $30 million in aggregate principal amount of its 5.98% Senior Notes due 2033 (Senior Notes). The Senior Notes were issued as a series of debt securities under an Indenture, dated as of December 15, 2003, between the Company and The Bank of New York, as trustee (Indenture Trustee). The Senior Notes are secured by the lien of a matching aggregate principal amount of the Company's First Mortgage Bonds that were issued to the Indenture Trustee for the benefit of the holders of the Senior Notes and a junior lien on the Company's electric and natural gas utility property. The liens securing the Senior Notes may be released in certain circumstances. On February 10, 2004, the Company issued 2.3 million shares of its common stock and appurtenant preference share purchase rights to the public at a price per share of $23.32 in an underwritten public offering and received net proceeds from the offering of approximately $51.5 million, after deducting underwriting discounts and commissions and offering expenses payable by the Company. Approximately $24 million of the net proceeds was used to repay outstanding indebtedness. The remainder of the net proceeds of the sale of these shares was added to the Company's general funds and may be used for the repayment of outstanding debt obligations, for corporate development purposes (including the acquisition of other businesses and/or business assets), and for other general corporate purposes. 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, 2003, the Company could have issued approximately $313 million of additional first mortgage bonds. The Company's coverage of fixed charges including preferred dividends was 4.7 times and 4.8 times for the years ended December 31, 2003 and 2002, respectively. Additionally, the Company's first mortgage bond interest coverage was 7.4 times and 7.7 times for the years ended December 31, 2003 and 2002, respectively. Common stockholders' equity as a percent of total capitalization was 60 percent at December 31, 2003 and 2002. Centennial Energy Holdings, Inc. Centennial has two revolving credit agreements with various banks that supports $275 million of Centennial's $350 million commercial paper program. There were no outstanding borrowings under the Centennial credit agreements at December 31, 2003. Under the Centennial commercial paper program, $32.5 million was outstanding at December 31, 2003. The Centennial commercial paper borrowings are classified as long-term debt as Centennial intends to refinance these borrowings on a long-term basis through continued Centennial commercial paper borrowings and as further supported by the Centennial credit agreements. The Centennial credit agreements are for $137.5 million each. One of these agreements expires on September 3, 2004, and allows for subsequent borrowings up to a term of one year. The other agreement expires on September 5, 2006. Centennial intends to negotiate the extension or replacement of these agreements prior to their maturities. Centennial has an uncommitted long-term master shelf agreement that allows for borrowings of up to $400 million. Under the terms of the master shelf agreement, $384.0 million was outstanding at December 31, 2003. To meet potential future financing needs, Centennial may pursue other financing arrangements, including private and/or public financing. Centennial's goal is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. If Centennial were to experience a minor downgrade of its credit ratings, it would not anticipate any change in its ability to access the capital markets. However, in such event, Centennial would expect a nominal basis point increase in overall interest rates with respect to its cost of borrowings. If Centennial were to experience a significant downgrade of its credit ratings, which it does not currently anticipate, it may need to borrow under its committed bank lines. To the extent Centennial needs to borrow under its committed bank lines, it would be expected to incur increased annualized interest expense on its variable rate debt of approximately $49,000 (after tax) based on December 31, 2003, variable rate borrowings. Based on Centennial's overall interest rate exposure at December 31, 2003, this change would not have a material effect on the Company's results of operations or cash flows. Prior to the maturity of the Centennial credit agreements, Centennial plans to negotiate the extension or replacement of these agreements that provide credit support to access the capital markets. In the event Centennial was unable to successfully negotiate these agreements, or in the event the fees on such facilities became too expensive, which Centennial does not currently anticipate, it would seek alternative funding. One source of alternative funding might involve the securitization of certain Centennial assets. In order to borrow under Centennial's credit agreements and the Centennial uncommitted long-term master shelf agreement, Centennial and certain of its subsidiaries must be in compliance with the applicable covenants and certain other conditions. The significant covenants include maximum capitalization ratios, minimum interest coverage ratios, minimum consolidated net worth, limitation on priority debt, limitation on sale of assets and limitation on loans and investments. Centennial and such subsidiaries were in compliance with these covenants and met the required conditions at December 31, 2003. In the event Centennial or such subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued as previously described. Certain of Centennial's financing agreements contain cross- default provisions. These provisions state that if Centennial or any subsidiary of Centennial fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the applicable agreements will be in default. Certain of Centennial's financing agreements and Centennial's practice limit the amount of subsidiary indebtedness. Williston Basin Interstate Pipeline Company Williston Basin has an uncommitted long-term master shelf agreement that allows for borrowings of up to $100 million. Under the terms of the master shelf agreement, $55.0 million was outstanding at December 31, 2003. In order to borrow under Williston Basin's uncommitted long- term master shelf agreement, it must be in compliance with the applicable covenants and certain other conditions. The significant covenants include limitation on consolidated indebtedness, limitation on priority debt, limitation on sale of assets and limitation on investments. Williston Basin was in compliance with these covenants and met the required conditions at December 31, 2003. In the event Williston Basin does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued. Off balance sheet arrangements Centennial has unconditionally guaranteed a portion of certain bank borrowings of MPX in connection with the Company's equity method investment in the natural gas-fired electric generating facility in Brazil, as discussed in Item 8 -- Financial Statements and Supplementary Data - Note 2. The Company, through MDU Brasil, owns 49 percent of MPX. The main business purpose of Centennial extending the guarantee to MPX's creditors is to enable MPX to obtain lower borrowing costs. At December 31, 2003, the aggregate amount of borrowings outstanding subject to these guarantees was $45.5 million and the scheduled repayment of these borrowings is $11.0 million in 2004, $10.7 million in 2005, $10.7 million in 2006, $10.7 million in 2007 and $2.4 million in 2008. The individual investor (who through EBX Empreendimentos Ltda. (EBX), a Brazilian company, owns 51 percent of MPX) has also guaranteed a portion of these loans. In the event MPX defaults under its obligation, Centennial and the individual investor would be required to make payments under their guarantees. Centennial and the individual investor have entered into reimbursement agreements under which they have agreed to reimburse each other to the extent they may be required to make any guarantee payments in excess of their proportionate ownership share in MPX. These guarantees are not reflected on the Consolidated Balance Sheets. As of December 31, 2003, Centennial was contingently liable for the performance of certain of its subsidiaries under approximately $360 million of surety bonds. These bonds are principally for construction contracts and reclamation obligations of these subsidiaries entered into in the normal course of business. Centennial indemnifies the respective surety bond companies against any exposure under the bonds. The purpose of Centennial's indemnification is to allow the subsidiaries to obtain bonding at competitive rates. In the event a subsidiary of the Company does not fulfill its obligations in relation to its bonded contract or obligation, Centennial may be required to make payments under its indemnification. A large portion of these contingent commitments are expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. The surety bonds were not reflected on the Consolidated Balance Sheets. Contractual obligations and commercial commitments For more information on the Company's contractual obligations on long-term debt, operating leases and purchase commitments, see Item 8 -- Financial Statements and Supplementary Data - Notes 8 and 19. At December 31, 2003, the Company's commitments under these obligations were as follows: There- 2004 2005 2006 2007 2008 after Total (In millions) Long-term debt $ 27.6 $ 70.9 $173.2 $105.8 $160.2 $429.4 $ 967.1 Operating leases 18.1 12.4 8.7 5.1 3.9 22.1 70.3 Purchase commitments 167.2 67.2 50.1 31.0 30.9 146.3 492.7 $212.9 $150.5 $232.0 $141.9 $195.0 $597.8 $1,530.1 Effects of Inflation Inflation did not have a significant effect on the Company's operations in 2003, 2002 or 2001. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to the impact of market fluctuations associated with commodity prices, interest rates and foreign currency. The Company has policies and procedures to assist in controlling these market risks and utilizes derivatives to manage a portion of its risk. The Company's policy allows the use of derivative instruments as part of an overall energy price, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. The Company's policy prohibits the use of derivative instruments for speculating to take advantage of market trends and conditions and the Company has procedures in place to monitor compliance with its policies. The Company is exposed to credit-related losses in relation to derivative instruments in the event of nonperformance by counterparties. The Company's policy requires settlement of natural gas and oil price derivative instruments monthly and all interest rate derivative transactions must be settled over a period that will not exceed 90 days, and any foreign currency derivative transaction settlement periods may not exceed a 12- month period. The Company has policies and procedures that management believes minimize credit-risk exposure. These policies and procedures include an evaluation of potential counterparties' credit ratings and credit exposure limitations. Accordingly, the Company does not anticipate any material effect to its financial position or results of operations as a result of nonperformance by counterparties. In the event a derivative instrument being accounted for as a cash flow hedge does not qualify for hedge accounting because it is no longer highly effective in offsetting changes in cash flows of a hedged item; or if the derivative instrument expires or is sold, terminated or exercised; or if management determines that designation of the derivative instrument as a hedge instrument is no longer appropriate, hedge accounting will be discontinued, and the derivative instrument would continue to be carried at fair value with changes in its fair value recognized in earnings. In these circumstances, the net gain or loss at the time of discontinuance of hedge accounting would remain in other accumulated comprehensive income (loss) until the period or periods during which the hedged forecasted transaction affects earnings, at which time the net gain or loss would be reclassified into earnings. In the event a cash flow hedge is discontinued because it is unlikely that a forecasted transaction will occur, the derivative instrument would continue to be carried on the balance sheet at its fair value, and gains and losses that had accumulated in other comprehensive income (loss) would be recognized immediately in earnings. In the event of a sale, termination or extinguishment of a foreign currency derivative, the resulting gain or loss would be recognized immediately in earnings. The Company's policy requires approval to terminate a derivative instrument prior to its original maturity. Commodity price risk -- A subsidiary of the Company utilizes natural gas and oil price swap and collar agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil on the subsidiary's forecasted sales of natural gas and oil production. Each of the natural gas and oil price swap and collar agreements were designated as a hedge of the forecasted sale of natural gas and oil production. On an ongoing basis, the balance sheet is adjusted to reflect the current fair market value of the swap and collar agreements. The related gains or losses on these agreements are recorded in common stockholders' equity as a component of other comprehensive income (loss). At the date the underlying transaction occurs, the amounts accumulated in other comprehensive income (loss) are reported in the Consolidated Statements of Income. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded directly in earnings. The following table summarizes hedge agreements entered into by an indirect wholly owned subsidiary of the Company, as of December 31, 2003. These agreements call for the subsidiary of the Company to receive fixed prices and pay variable prices. (Notional amount and fair value in thousands) Weighted Average Notional Fixed Price Amount (Per MMBtu) (In MMBtu's) Fair Value Natural gas swap agreements maturing in 2004 $ 5.17 11,890 $ (1,645) Weighted Average Floor/Ceiling Notional Price Amount (Per MMBtu) (In MMBtu's) Fair Value Natural gas collar agreements maturing in 2004 $4.34/$4.94 6,771 $ (3,481) Weighted Average Notional Fixed Price Amount (Per barrel) (In barrels) Fair Value Oil swap agreements maturing in 2004 $ 29.25 366 $ (341) The following table summarizes hedge agreements entered into by the subsidiary of the Company, as of December 31, 2002. These agreements call for the subsidiary to receive fixed prices and pay variable prices. (Notional amount and fair value in thousands) Weighted Average Notional Fixed Price Amount (Per MMBtu) (In MMBtu's) Fair Value Natural gas swap agreements maturing in 2003 $ 3.96 1,186 $ (731) Weighted Average Floor/Ceiling Notional Price Amount (Per MMBtu) (In MMBtu's) Fair Value Natural gas collar agreements maturing in 2003 $3.33/$3.89 22,365 $ (6,256) Weighted Average Floor/Ceiling Notional Price Amount (Per barrel) (In barrels) Fair Value Oil collar agreements maturing in 2003 $24.50/$27.62 639 $ (457) Interest rate risk -- The Company uses fixed and variable rate long-term debt to partially finance capital expenditures and mandatory debt retirements. These debt agreements expose the Company to market risk related to changes in interest rates. The Company manages this risk by taking advantage of market conditions when timing the placement of long-term or permanent financing. The Company has also historically used interest rate swap agreements to manage a portion of the Company's interest rate risk and may take advantage of such agreements in the future to minimize such risk. The following table shows the amount of debt, including current portion, and related weighted average interest rates, both by expected maturity dates, as of December 31, 2003. Weighted average variable rates are based on forward rates as of December 31, 2003. There- Fair 2004 2005 2006 2007 2008 after Total Value (Dollars in millions) Long-term debt: Fixed rate $27.6 $ 70.9 $100.7 $105.8 $160.2 $429.4 $894.6 $941.5 Weighted average interest rate 5.8% 8.0% 6.5% 8.2% 4.4% 6.4% 6.4% - Variable rate - - $ 72.5 - - - $ 72.5 $ 71.0 Weighted average interest rate - - 1.1% - - - 1.1% - For further information on derivative instruments and fair value of other financial instruments, see Item 8 -- Financial Statements and Supplementary Data - Notes 5 and 6. Foreign currency risk -- MDU Brasil has a 49 percent equity investment in a 220- megawatt natural gas-fired electric generating facility (Brazil Generating Facility) in Brazil, which has a portion of its borrowings and payables denominated in U.S. dollars. MDU Brasil has exposure to currency exchange risk as a result of fluctuations in currency exchange rates between the U.S. dollar and the Brazilian real. The functional currency for the Brazil Generating Facility is the Brazilian real. For further information on this investment, see Item 8 -- Financial Statements and Supplementary Data - Note 2. MDU Brasil's equity income from this Brazilian investment is impacted by fluctuations in currency exchange rates on transactions denominated in a currency other than the Brazilian real, including the effects of changes in currency exchange rates with respect to the Brazil Generating Facility's U.S. dollar denominated obligations, excluding a U.S. dollar denominated loan from Centennial Energy Resources International Inc (Centennial International), an indirect wholly owned subsidiary of the Company, as discussed below. At December 31, 2003, these U.S. dollar denominated obligations approximated $66.9 million. If, for example, the value of the Brazilian real decreased in relation to the U.S. dollar by 10 percent, MDU Brasil, with respect to its interest in the Brazil Generating Facility, would record a foreign currency transaction loss in net income of approximately $3.0 million (after tax) based on the above U.S. dollar denominated obligations at December 31, 2003. The Brazil Generating Facility also had approximately US$9.5 million of Brazilian real denominated obligations at December 31, 2003. Adjustments attributable to the translation from the Brazilian real to the U.S. dollar for assets, liabilities, revenues and expenses were recorded in accumulated other comprehensive income (loss) at December 31, 2003. Foreign currency translation adjustments on the Brazil Generating Facility's U.S. dollar denominated borrowings payable to the subsidiary of $20.0 million at December 31, 2003, are recorded in accumulated other comprehensive income (loss). The investment of Centennial International in the Brazil Generating Facility at December 31, 2003, was approximately $25.2 million including undistributed earnings of $4.6 million. Centennial has guaranteed Brazil Generating Facility obligations and loans of approximately $45.5 million as of December 31, 2003. A portion of the Brazil Generating Facility's foreign currency exchange risk is being managed through contractual provisions, which are largely indexed to the U.S. dollar, contained in the Brazil Generating Facility's power purchase agreement with Petrobras. The Brazil Generating Facility has also historically used derivative instruments to manage a portion of its foreign currency risk and may utilize such instruments in the future. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 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 accounting principles generally accepted in the United States of America as applied to the company's regulated and nonregulated businesses and necessarily include some amounts that are based on informed judgments and estimates of management. To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls designed to provide assurance, on a cost-effective basis, that transactions are carried out in accordance with management's authorizations and that assets are safeguarded against loss from unauthorized use or disposition. The system includes an organizational structure which provides an appropriate segregation of responsibilities, effective selection and training of personnel, written policies and procedures and periodic reviews by the Internal Auditing Department. In addition, the company has a policy which requires certain employees to acknowledge their responsibility for ethical conduct. Management believes that these measures provide for a system that is effective and reasonably assures that all transactions are properly recorded for the preparation of financial statements. Management modifies and improves its system of internal accounting controls in response to changes in business conditions. The company's Internal Auditing 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 Deloitte & Touche LLP, independent auditors, to discuss auditing and financial matters and to assure that each is carrying out its responsibilities. The internal auditors and Deloitte & Touche LLP have full and free access to the Audit Committee, without management present, to discuss auditing, internal accounting control and financial reporting matters. /s/MARTIN A. WHITE /s/WARREN L. ROBINSON Martin A. White Warren L. Robinson Chairman of the Board Executive Vice President President and Chief and Chief Financial Executive Officer Officer MDU RESOURCES GROUP, INC. CONSOLIDATED STATEMENTS OF INCOME Years ended December 31, 2003 2002 2001 (In thousands, except per share amounts) Operating revenues: Electric, natural gas distribution and pipeline and energy services $ 641,062 $ 459,409 $ 903,334 Utility services, natural gas and oil production, construction materials and mining and other 1,711,127 1,572,128 1,320,298 2,352,189 2,031,537 2,223,632 Operating expenses: Fuel and purchased power 62,037 56,010 57,393 Purchased natural gas sold 184,171 92,528 529,356 Operation and maintenance: Electric, natural gas distribution and pipeline and energy services 141,307 129,845 129,372 Utility services, natural gas and oil production, construction materials and mining and other 1,384,015 1,263,183 1,038,899 Depreciation, depletion and amortization 188,337 157,961 139,917 Taxes, other than income 80,250 65,893 55,427 2,040,117 1,765,420 1,950,364 Operating income 312,072 266,117 273,268 Other income -- net (Note 1) 22,207 13,572 26,821 Interest expense 52,794 45,015 45,899 Income before income taxes 281,485 234,674 254,190 Income taxes 98,572 86,230 98,341 Income before cumulative effect of accounting change 182,913 148,444 155,849 Cumulative effect of accounting change (Note 9) (7,589) --- --- Net income 175,324 148,444 155,849 Dividends on preferred stocks 717 756 762 Earnings on common stock $ 174,607 $ 147,688 $ 155,087 Earnings per common share -- basic: Earnings before cumulative effect of accounting change $ 1.64 $ 1.39 $ 1.54 Cumulative effect of accounting change (.07) --- --- Earnings per common share -- basic $ 1.57 $ 1.39 $ 1.54 Earnings per common share -- diluted: Earnings before cumulative effect of accounting change $ 1.62 $ 1.38 $ 1.52 Cumulative effect of accounting change (.07) --- --- Earnings per common share -- diluted $ 1.55 $ 1.38 $ 1.52 Dividends per common share $ .6600 $ .6266 $ .6000 Weighted average common shares outstanding -- basic 111,483 106,115 100,908 Weighted average common shares outstanding -- diluted 112,460 106,863 101,803 Pro forma amounts assuming retroactive application of accounting change: Net income $ 182,913 $ 146,052 $ 152,933 Earnings per common share -- basic $ 1.64 $ 1.37 $ 1.51 Earnings per common share -- diluted $ 1.62 $ 1.36 $ 1.49 The accompanying notes are an integral part of these consolidated financial statements. MDU RESOURCES GROUP, INC. CONSOLIDATED BALANCE SHEETS December 31, 2003 2002 (In thousands, except shares and per share amounts) ASSETS Current assets: Cash and cash equivalents $ 86,341 $ 67,556 Receivables, net 357,677 325,395 Inventories 114,051 93,123 Deferred income taxes 3,104 8,877 Prepayments and other current assets 52,367 42,597 613,540 537,548 Investments 44,975 42,864 Property, plant and equipment 3,397,619 2,961,808 Less accumulated depreciation, depletion and amortization 1,175,326 1,019,438 2,222,293 1,942,370 Deferred charges and other assets: Goodwill (Note 3) 199,427 190,999 Other intangible assets, net (Note 3) 193,454 176,164 Other 106,903 106,976 499,784 474,139 $3,380,592 $2,996,921 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Short-term borrowings (Note 7) $ --- $ 20,000 Long-term debt and preferred stock due within one year 27,646 22,183 Accounts payable 150,316 132,120 Taxes payable 15,358 13,108 Dividends payable 19,442 17,959 Other accrued liabilities 101,299 94,275 314,061 299,645 Long-term debt (Note 8) 939,450 819,558 Deferred credits and other liabilities: Deferred income taxes 444,779 374,097 Other liabilities 231,666 203,676 676,445 577,773 Preferred stock subject to mandatory redemption (Note 10) --- 1,200 Commitments and contingencies (Notes 16, 18 and 19) Stockholders' equity: Preferred stocks (Note 10) 15,000 15,000 Common stockholders' equity: Common stock (Note 11) Authorized -- 250,000,000 shares, $1.00 par value Issued - 113,716,632 shares in 2003 and 74,282,038 shares in 2002 113,717 74,282 Other paid-in capital 757,787 748,095 Retained earnings 575,287 474,798 Accumulated other comprehensive loss (7,529) (9,804) Treasury stock at cost - 359,281 shares in 2003 and 239,521 shares in 2002 (3,626) (3,626) Total common stockholders' equity 1,435,636 1,283,745 Total stockholders' equity 1,450,636 1,298,745 $3,380,592 $2,996,921 The accompanying notes are an integral part of these consolidated financial statements. [Enlarge/Download Table] MDU RESOURCES GROUP, INC. CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY Years ended December 31, 2003, 2002 and 2001 Accumu- lated Other Compre- Other hensive Common Stock Paid-in Retained Income Treasury Stock Shares Amount Capital Earnings (Loss) Shares Amount Total (In thousands, except shares) Balance at December 31, 2000 65,267,567 $ 65,268 $518,771 $300,647 $ --- (239,521) $(3,626) $ 881,060 Comprehensive income: Net income --- --- --- 155,849 --- --- --- 155,849 Other comprehensive income, net of tax - Net unrealized gain on derivative instruments qualifying as hedges --- --- --- --- 2,218 --- --- 2,218 Total comprehensive income --- --- --- --- --- --- --- 158,067 Dividends on preferred stocks --- --- --- (762) --- --- --- (762) Dividends on common stock --- --- --- (61,093) --- --- --- (61,093) Issuance of common stock, net 4,749,284 4,749 127,750 --- --- --- --- 132,499 Balance at December 31, 2001 70,016,851 70,017 646,521 394,641 2,218 (239,521) (3,626) 1,109,771 Comprehensive income: Net income --- --- --- 148,444 --- --- --- 148,444 Other comprehensive loss, net of tax - Net unrealized loss on derivative instruments qualifying as hedges --- --- --- --- (6,759) --- --- (6,759) Minimum pension liability adjustment --- --- --- --- (4,464) --- --- (4,464) Foreign currency translation adjustment --- --- --- --- (799) --- --- (799) Total comprehensive income --- --- --- --- --- --- --- 136,422 Dividends on preferred stocks --- --- --- (756) --- --- --- (756) Dividends on common stock --- --- --- (67,531) --- --- --- (67,531) Issuance of common stock, net 4,265,187 4,265 101,574 --- --- --- --- 105,839 Balance at December 31, 2002 74,282,038 74,282 748,095 474,798 (9,804) (239,521) (3,626) 1,283,745 Comprehensive income: Net income --- --- --- 175,324 --- --- --- 175,324 Other comprehensive income, net of tax - Net unrealized gain on derivative instruments qualifying as hedges --- --- --- --- 1,206 --- --- 1,206 Minimum pension liability adjustment --- --- --- --- 21 --- --- 21 Foreign currency translation adjustment --- --- --- --- 1,048 --- --- 1,048 Total comprehensive income --- --- --- --- --- --- --- 177,599 Dividends on preferred stocks --- --- --- (717) --- --- --- (717) Dividends on common stock --- --- --- (74,118) --- --- --- (74,118) Issuance of common stock, net (pre-split) 1,442,220 1,442 45,260 --- --- --- --- 46,702 Three-for-two common stock split (Note 11) 37,862,129 37,862 (37,862) --- --- (119,760) --- --- Issuance of common stock, net (post-split) 130,245 131 2,294 --- --- --- --- 2,425 Balance at December 31, 2003 113,716,632 $113,717 $757,787 $575,287 $(7,529) (359,281) $(3,626) $1,435,636 <FN> The accompanying notes are an integral part of these consolidated statements. </FN> MDU RESOURCES GROUP, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS Years ended December 31, 2003 2002 2001 (In thousands) Operating activities: Net income $ 175,324 $ 148,444 $155,849 Cumulative effect of accounting change 7,589 --- --- Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 188,337 157,961 139,917 Deferred income taxes 64,587 30,759 21,014 Changes in current assets and liabilities, net of acquisitions: Receivables (9,572) (19,739) 127,267 Inventories (13,023) 6,537 (26,540) Other current assets (13,383) (5,562) (2,792) Accounts payable 2,748 11,600 (90,576) Other current liabilities 10,486 (9,499) 34,331 Other noncurrent changes 5,304 5,830 (9,916) Net cash provided by operating activities 418,397 326,331 348,554 Investing activities: Capital expenditures (313,053) (276,776) (269,542) Acquisitions, net of cash acquired (132,653) (92,657) (112,743) Net proceeds from sale or disposition of property 14,439 16,217 51,641 Investments 2,491 (4,666) 2,760 Additions to notes receivable --- --- (23,813) Proceeds from notes receivable 7,812 4,000 4,000 Net cash used in investing activities (420,964) (353,882) (347,697) Financing activities: Net change in short-term borrowings (20,000) 20,000 (8,000) Issuance of long-term debt 219,895 129,072 122,283 Repayment of long-term debt (105,740) (82,523) (115,062) Retirement of preferred stock --- (100) (100) Proceeds from issuance of common stock, net 568 55,134 67,176 Dividends paid (73,371) (68,287) (61,855) Net cash provided by financing activities 21,352 53,296 4,442 Increase in cash and cash equivalents 18,785 25,745 5,299 Cash and cash equivalents -- beginning of year 67,556 41,811 36,512 Cash and cash equivalents -- end of year $ 86,341 $ 67,556 $ 41,811 The accompanying notes are an integral part of these consolidated financial statements. NOTE 1 Summary of Significant Accounting Policies Basis of presentation The consolidated financial statements of MDU Resources Group, Inc. and its subsidiaries (Company) include the accounts of the following businesses: electric, natural gas distribution, utility services, pipeline and energy services, natural gas and oil production, construction materials and mining, and independent power production and other. The electric, natural gas distribution, and pipeline and energy services businesses are substantially all regulated. Utility services, natural gas and oil production, construction materials and mining, and independent power production and other are nonregulated. For further descriptions of the Company's businesses, see Note 14. The statements also include the ownership interests in the assets, liabilities and expenses of two jointly owned electric generation stations. The Company uses the equity method of accounting for certain investments including its 49 percent interest in MPX Participacoes, Ltda. (MPX), which was formed to develop electric generation and transmission, steam generation, power equipment and coal mining projects in Brazil. For more information on the Company's equity investments, see new accounting standards in Note 1, as well as Note 2. The Company's regulated businesses are subject to various state and federal agency regulation. The accounting policies followed by these businesses are generally subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the Company's nonregulated businesses. The Company's regulated businesses account for certain income and expense items under the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Regulation." SFAS No. 71 requires these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively, based on the expected regulatory treatment in future rates. The expected recovery or flowback of these deferred items generally is based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistently with the regulatory treatment established by the FERC and the applicable state public service commissions. See Note 4 for more information regarding the nature and amounts of these regulatory deferrals. Prior to the sale of the Company's coal operations in 2001, as discussed in Note 14, intercompany coal sales, which were made at prices approximately the same as those charged to others, and the related utility fuel purchases were not eliminated in accordance with the provisions of SFAS No. 71. All other significant intercompany balances and transactions have been eliminated in consolidation. Cash and cash equivalents The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Allowance for doubtful accounts The Company's allowance for doubtful accounts as of December 31, 2003 and 2002, was $8.1 million and $8.2 million, respectively. Natural gas in underground storage Natural gas in underground storage for the Company's regulated operations is carried at cost using the last-in, first-out method. The portion of the cost of natural gas in underground storage expected to be used within one year was included in inventories and amounted to $19.6 million at December 31, 2003, and $18.2 million at December 31, 2002. The remainder of natural gas in underground storage was included in other assets and was $42.6 million at December 31, 2003, and $42.2 million at December 31, 2002. Inventories Inventories, other than natural gas in underground storage for the Company's regulated operations, consisted primarily of aggregates held for resale of $54.7 million and $39.6 million, materials and supplies of $27.2 million and $23.0 million, and other inventories of $12.6 million and $12.3 million, as of December 31, 2003 and 2002, respectively. These inventories were stated at the lower of average cost or market. Property, plant and equipment Additions to property, plant and equipment are recorded at cost when first placed in service. Acquired aggregate reserves at the Company's construction materials and mining business are classified based on type of ownership. Owned mineral rights are classified as property, plant and equipment, whereas leased mineral rights are classified as other intangible assets, net. For more information on other intangible assets, net, see Note 3. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost of the asset is charged to accumulated depreciation. With respect to the retirement or disposal of all other assets, except for natural gas and oil production properties as described in natural gas and oil properties in Note 1, the resulting gains or losses are recognized as a component of income. The Company is permitted to capitalize an allowance for funds used during construction (AFUDC) on regulated construction projects and to include such amounts in rate base when the related facilities are placed in service. In addition, the Company capitalizes interest, when applicable, on certain construction projects associated with its other operations. The amount of AFUDC and interest capitalized was $7.4 million, $7.6 million and $6.6 million in 2003, 2002 and 2001, respectively. Generally, property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets, except for depletable reserves, which are depleted based on the units- of-production method based on recoverable deposits, and natural gas and oil production properties, which are amortized on the units-of- production method based on total reserves. Property, plant and equipment at December 31, 2003 and 2002, was as follows: Estimated Depreciable Life 2003 2002 in Years (Dollars in thousands, as applicable) Regulated: Electric: Electric generation, distribution and transmission plant $ 639,893 $ 619,230 4-50 Natural gas distribution: Natural gas distribution plant 252,591 244,930 4-40 Pipeline and energy services: Natural gas transmission, gathering and storage facilities 340,841 262,971 3-70 Nonregulated: Utility services: Land 2,505 2,601 --- Buildings and improvements 10,123 8,768 10-40 Machinery, vehicles and equipment 58,843 54,833 2-10 Other 5,400 4,458 3-10 Pipeline and energy services: Natural gas gathering and other facilities 119,613 108,179 3-20 Energy services 1,339 1,270 3-15 Natural gas and oil production: Natural gas and oil properties 862,839 748,843 (a) Other 8,518 6,945 5-7 Construction materials and mining: Land 89,545 85,376 --- Buildings and improvements 48,907 43,144 1-40 Machinery, vehicles and equipment 569,295 493,349 1-25 Construction in progress 14,392 10,151 --- Depletable reserves 171,841 172,235 (b) Independent power production and other: Electric generation 153,947 58,000 5-30 Construction in progress 29,805 19,342 --- Land 2,001 2,001 --- Other 15,381 15,182 3-20 Less accumulated depreciation, depletion and amortization 1,175,326 1,019,438 Net property, plant and equipment $2,222,293 $1,942,370 (a) Amortized on the units-of-production method based on total proved reserves at an Mcf equivalent rate of $.89, $.80, and $.78 for the years ended December 31, 2003, 2002 and 2001, respectively. Includes natural gas and oil production properties accounted for under the full-cost method, of which $104,339 and $145,692 were excluded from amortization at December 31, 2003 and 2002, respectively. (b) Depleted based on the units-of-production method based on recoverable deposits. Impairment of long-lived assets The Company reviews the carrying values of its long-lived assets, excluding goodwill, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, compared to the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. No long-lived assets have been impaired and, accordingly, no impairment losses have been recorded in 2003, 2002 and 2001. Unforeseen events and changes in circumstances could require the recognition of other impairment losses at some future date. Goodwill Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a business combination. On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangibles," and ceased amortization of its goodwill. Goodwill is required to be tested for impairment annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. In accordance with SFAS No. 142, the Company performed its transitional goodwill impairment testing as of January 1, 2002, and performed its annual goodwill impairment testing as of October 31, 2003 and 2002, and determined that no impairments existed at those dates. Therefore, no impairment loss has been recorded for the years ended December 31, 2003 and 2002. For more information on goodwill, see Note 3. Natural gas and oil properties The Company uses the full-cost method of accounting for its natural gas and oil production activities. Under this method, all costs incurred in the acquisition, exploration and development of natural gas and oil properties are capitalized and amortized on the units-of-production method based on total proved reserves. 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 recognized. 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 based on single point-in-time spot market prices, as mandated under the rules of the Securities and Exchange Commission, and the lower of cost or fair value of unproved properties. Future net revenue is estimated based on end-of-quarter spot market prices adjusted for contracted price changes. If capitalized costs exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter unless subsequent price changes eliminate or reduce an indicated write-down. At December 31, 2003 and 2002, the Company's full-cost ceiling exceeded the Company's capitalized cost. However, sustained downward movements in natural gas and oil prices subsequent to December 31, 2003, could result in a future write-down of the Company's natural gas and oil properties. The following table summarizes the Company's natural gas and oil properties not subject to amortization at December 31, 2003, in total and by year in which such costs were incurred: Year Costs Incurred 2000 Total 2003 2002 2001 and prior (In thousands) Acquisition $ 48,355 $ 630 $17,108 $--- $30,617 Development 39,160 28,351 5,120 --- 5,689 Exploration 4,885 4,828 --- 23 34 Capitalized interest 11,939 5,642 6,297 --- --- Total costs not subject to amortization $104,339 $39,451 $28,525 $ 23 $36,340 Costs not subject to amortization as of December 31, 2003, consisted primarily of lease acquisition costs, unevaluated drilling costs and capitalized interest associated with coalbed development in the Powder River Basin of Montana and Wyoming. The Company expects that the majority of these costs will be evaluated over the next three- to five- year period and included in the amortization base as the properties are developed and evaluated and proved reserves are established or impairment is determined. Revenue recognition Revenue is recognized when the earnings process is complete, as evidenced by an agreement between the customer and the Company, when delivery has occurred or services have been rendered, when the fee is fixed or determinable and when collection is probable. The Company recognizes utility revenue each month based on the services provided to all utility customers during the month. The Company recognizes construction contract revenue at its construction businesses using the percentage-of-completion method as discussed later. The Company recognizes revenue from natural gas and oil production activities only on that portion of production sold and allocable to the Company's ownership interest in the related well. Revenues at the independent power production operations are recognized based on electricity delivered and capacity provided, pursuant to contractual commitments. The Company recognizes all other revenues when services are rendered or goods are delivered. Percentage-of-completion method The Company recognizes construction contract revenue from fixed price and modified fixed price construction contracts at its construction businesses using the percentage-of-completion method, measured by the percentage of costs incurred to date to estimated total costs for each contract. Costs in excess of billings on uncompleted contracts of $31.8 million and $19.4 million for the years ended December 31, 2003 and 2002, respectively, represents revenues recognized in excess of amounts billed and was included in receivables, net. Billings in excess of costs on uncompleted contracts of $20.4 million and $24.5 million for the years ended December 31, 2003 and 2002, respectively, represents billings in excess of revenues recognized and was included in accounts payable. Also included in receivables, net were amounts representing balances billed but not paid by customers under retainage provisions in contracts that amounted to $34.3 million and $25.6 million as of December 31, 2003 and 2002, respectively, which are expected to be paid within one year or less. Derivative instruments The Company's policy allows the use of derivative instruments as part of an overall energy price, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. The Company's policy prohibits the use of derivative instruments for speculating to take advantage of market trends and conditions and the Company has procedures in place to monitor compliance with its policies. The Company is exposed to credit-related losses in relation to derivative instruments in the event of nonperformance by counterparties. The Company's policy requires settlement of natural gas and oil price derivative instruments monthly and all interest rate derivative transactions must be settled over a period that will not exceed 90 days, and any foreign currency derivative transaction settlement periods may not exceed a 12-month period. The Company has policies and procedures that management believes minimize credit-risk exposure. These policies and procedures include an evaluation of potential counterparties' credit ratings and credit exposure limitations. Accordingly, the Company does not anticipate any material effect to its financial position or results of operations as a result of nonperformance by counterparties. Advertising The Company expenses advertising costs as incurred and the amount of advertising expense for the years 2003, 2002 and 2001, was $3.9 million, $3.4 million and $2.9 million, respectively. Natural gas costs recoverable or refundable through rate adjustments Under the terms of certain orders of the applicable state public service commissions, the Company is deferring natural gas commodity, transportation and storage costs that 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 a period ranging from 24 months to 28 months from the time such costs are paid. Natural gas costs recoverable through rate adjustments amounted to $10.5 million at December 31, 2003, which is included in prepayments and other current assets. Natural gas costs refundable through rate adjustments amounted to $2.4 million at December 31, 2002, which is included in other accrued liabilities. Insurance Certain subsidiaries of the Company are insured for workers' compensation losses, subject to deductibles ranging up to $500,000 per occurrence. Automobile liability and general liability losses are insured, subject to deductibles ranging up to $500,000 per accident or occurrence. These subsidiaries have excess coverage on a claims first- made basis beyond the deductible levels. The subsidiaries of the Company are retaining losses up to the deductible amounts accrued on the basis of estimates of liability for claims incurred and claims incurred but not reported. Other income - net Other income - net consisted of the following: Years ended December 31, 2003 2002 2001 (In thousands) Interest and dividend income $ 6,722 $ 8,160 $ 5,734 Earnings from equity method investments (Note 2) 5,968 1,341 154 Other income 9,517 4,071 20,933 Total other income - net $22,207 $13,572 $26,821 Income taxes The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company's assets and liabilities. Excess deferred income tax balances associated with the Company's rate-regulated activities resulting from the Company's adoption of SFAS No. 109, "Accounting for Income Taxes," have been recorded as a regulatory liability and are included in other liabilities. These regulatory liabilities are expected to be reflected as a reduction in future rates charged to customers in accordance with applicable regulatory procedures. The Company uses the deferral method of accounting for investment tax credits and amortizes the credits on electric and natural gas distribution plant over various periods that conform to the ratemaking treatment prescribed by the applicable state public service commissions. Foreign currency translation adjustment The functional currency of the Company's investment in a 220-megawatt natural gas-fired electric generating facility in Brazil, as further discussed in Note 2, is the Brazilian real. Translation from the Brazilian real to the U.S. dollar for assets and liabilities is performed using the exchange rate in effect at the balance sheet date. Revenues and expenses have been translated using the weighted average exchange rate for each month prevailing during the period reported. Adjustments resulting from such translations are reported as a separate component of other comprehensive income (loss) in common stockholders' equity. Transaction gains and losses resulting from the effect of exchange rate changes on transactions denominated in a currency other than the functional currency of the reporting entity are recorded in income. Common stock split On August 14, 2003, the Company's Board of Directors approved a three- for-two common stock split. For more information on the common stock split, see Note 11. Earnings per common share Basic earnings per common share were computed by dividing earnings on common stock by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the year, plus the effect of outstanding stock options, restricted stock grants and performance share awards. For the years ended December 31, 2003, 2002 and 2001, 209,805 shares, 3,674,925 shares and 225,945 shares, respectively, with an average exercise price of $24.56, $20.08 and $24.57, respectively, attributable to the exercise of outstanding options, were excluded from the calculation of diluted earnings per share because their effect was antidilutive. For the years ended December 31, 2003, 2002 and 2001, no adjustments were made to reported earnings in the computation of earnings per share. Common stock outstanding includes issued shares less shares held in treasury. Stock-based compensation The Company has stock option plans for directors, key employees and employees. In 2003, the Company adopted the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," and began expensing the fair market value of stock options for all awards granted on or after January 1, 2003. Compensation expense recognized for awards granted on or after January 1, 2003, for the year ended December 31, 2003, was $41,000 (after tax). As permitted by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123," the Company accounts for stock options granted prior to January 1, 2003, under APB Opinion No. 25, "Accounting for Stock Issued to Employees." No compensation expense has been recognized for stock options granted prior to January 1, 2003, as the options granted had an exercise price equal to the market value of the underlying common stock on the date of the grant. Since the Company adopted SFAS No. 123 effective January 1, 2003, for newly granted options only, the following table illustrates the effect on earnings and earnings per common share for the years ended December 31, 2003, 2002 and 2001, as if the Company had applied SFAS No. 123 and recognized compensation expense for all outstanding and unvested stock options based on the fair value at the date of grant: 2003 2002 2001 (In thousands, except per share amounts) Earnings on common stock, as reported $174,607 $147,688 $155,087 Stock-based compensation expense included in reported earnings, net of related tax effects 41 --- --- Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects (2,139) (2,862) (3,799) Pro forma earnings on common stock $172,509 $144,826 $151,288 Earnings per common share -- basic -- as reported: Earnings before cumulative effect of accounting change $ 1.64 $ 1.39 $ 1.54 Cumulative effect of accounting change (.07) --- --- Earnings per common share -- basic $ 1.57 $ 1.39 $ 1.54 Earnings per common share -- basic -- pro forma: Earnings before cumulative effect of accounting change $ 1.62 $ 1.36 $ 1.50 Cumulative effect of accounting change (.07) --- --- Earnings per common share -- basic $ 1.55 $ 1.36 $ 1.50 Earnings per common share -- diluted -- as reported: Earnings before cumulative effect of accounting change $ 1.62 $ 1.38 $ 1.52 Cumulative effect of accounting change (.07) --- --- Earnings per common share -- diluted $ 1.55 $ 1.38 $ 1.52 Earnings per common share -- diluted -- pro forma: Earnings before cumulative effect of accounting change $ 1.60 $ 1.36 $ 1.49 Cumulative effect of accounting change (.07) --- --- Earnings per common share -- diluted $ 1.53 $ 1.36 $ 1.49 For more information on the Company's stock-based compensation, see Note 12. Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for items such as impairment testing of long-lived assets, goodwill and natural gas and oil properties; fair values of acquired assets and liabilities under the purchase method of accounting; natural gas and oil reserves; property depreciable lives; tax provisions; uncollectible accounts; environmental and other loss contingencies; accumulated provision for revenues subject to refund; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; the valuation of stock-based compensation; and the fair value of derivative instruments, including the fair value of an embedded derivative in a power purchase agreement related to an equity method investment in Brazil, as discussed in Note 2. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Cash flow information Cash expenditures for interest and income taxes were as follows: Years ended December 31, 2003 2002 2001 (In thousands) Interest, net of amount capitalized $47,474 $37,788 $42,267 Income taxes $31,737 $60,988 $75,284 Reclassifications The Consolidated Statements of Income have been reclassified to include additional disclosures relating to the components comprising operating revenues and operation and maintenance expense. Certain other reclassifications have been made in the financial statements for prior years to conform to the current presentation. Such reclassifications had no effect on net income or stockholders' equity as previously reported. New accounting standards The Company has stock option plans for directors, key employees and employees. In 2003, the Company adopted the fair value recognition provisions of SFAS No. 123, and began expensing the fair market value of stock options for all awards granted on or after January 1, 2003. For a discussion of the effect of the adoption of the fair value recognition provisions of SFAS No. 123 on earnings and earnings per share, see stock-based compensation in Note 1. In June 2001, the Financial Accounting Standards Board (FASB) approved SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for the recorded amount or incurs a gain or loss. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. For more information on the adoption of SFAS No. 143, see Note 9. In April 2002, the FASB approved SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." FASB No. 4 required all gains or losses from extinguishment of debt to be classified as extraordinary items net of income taxes. SFAS No. 145 requires that gains and losses from extinguishment of debt be evaluated under the provisions of APB Opinion No. 30, and be classified as ordinary items unless they are unusual or infrequent or meet the specific criteria for treatment as an extraordinary item. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. The adoption of SFAS No. 145 did not have a material effect on the Company's financial position or results of operations. In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 clarifies the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. FIN 45 also requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing certain types of guarantees. Certain types of guarantees are not subject to the initial recognition and measurement provisions of FIN 45 but are subject to its disclosure requirements. The initial recognition and initial measurement provisions of FIN 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, regardless of the guarantor's fiscal year-end. The guarantor's previous accounting for guarantees issued prior to the date of the initial application of FIN 45 is not required to be revised or restated. The disclosure requirements in FIN 45 are effective for financial statements of interim or annual periods ended after December 15, 2002. The Company is applying the initial recognition and initial measurement provisions of FIN 45 to guarantees issued or modified after December 31, 2002. For more information on the Company's guarantees and the disclosure requirements of FIN 45, as applicable to the Company, see Note 19. In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 provides clarification on the financial accounting and reporting of derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities; and requires contracts with similar characteristics to be accounted for on a comparable basis. SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not have a material effect on the Company's financial position or results of operations. In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within the scope of SFAS No. 150 as a liability (or an asset in some circumstances). SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company will apply SFAS No. 150 to any financial instruments entered into or modified after May 31, 2003. Beginning in 2003, the Company reported its preferred stock subject to mandatory redemption as a liability in accordance with SFAS No. 150. The transition to SFAS No. 150 did not have a material effect on the Company's financial position or results of operations. In December 2003, the FASB issued FASB Interpretation No. 46 (revised 2003), "Consolidation of Variable Interest Entities" (FIN 46 (revised)), which revised FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46). FIN 46 (revised) clarifies the application of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated support. An enterprise shall consolidate a variable interest entity if that enterprise is the primary beneficiary. An enterprise is considered the primary beneficiary if it has a variable interest that will absorb a majority of the entity's expected losses, receive a majority of the entity's expected residual returns or both. FIN 46 (revised) shall be applied to all entities subject to FIN 46 (revised) no later than the end of the first reporting period that ends after March 15, 2004. However, an entity that applied FIN 46 to an entity prior to the effective date of FIN 46 (revised) shall either continue to apply FIN 46 until the effective date of FIN 46 (revised) or apply FIN 46 (revised) at an earlier date. The Company had evaluated the provisions of FIN 46 and determined that MPX is a variable interest entity. MPX was formed in August 2001, as a result of MDU Brasil Ltda. (MDU Brasil), an indirect wholly owned Brazilian subsidiary of the Company, entering into a joint venture agreement with a Brazilian firm. MDU Brasil has a 49 percent interest in MPX. Although the Company has determined that MPX is a variable interest entity, MDU Brasil is not considered the primary beneficiary of MPX because MDU Brasil does not absorb a majority of MPX's expected losses, receive a majority of MPX's expected residual returns or both. Therefore, MDU Brasil does not have a controlling financial interest in MPX and is not required to consolidate MPX in its financial statements. MPX is being accounted for under the equity method of accounting. For more information on this equity method investment, see Note 2. The adoption of FIN 46 did not have an effect on the Company's financial position or results of operations. The Company will continue to apply FIN 46 until the effective date of FIN 46 (revised). In December 2003, the FASB issued SFAS No. 132 (revised 2003), "Employers' Disclosures about Pension and Other Postretirement Benefits." SFAS No. 132 (revised 2003) retains the disclosure requirements contained in SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits," and requires additional disclosures about the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other postretirement benefit plans. SFAS No. 132 (revised 2003) is effective for financial statements with fiscal years ending after December 15, 2003. The interim-period disclosures required by SFAS No. 132 (revised 2003) are effective for interim periods beginning after December 15, 2003. The Company applied SFAS No. 132 (revised 2003) to its consolidated financial statements issued after December 15, 2003. For more information on the Company's pension and other postretirement benefits, see Note 16. In January 2004, the FASB issued FASB Staff Position No. FAS 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." FASB Staff Position No. FAS 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (2003 Medicare Act). SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other than Pension," requires enacted changes in relevant laws to be considered in current period measurements of postretirement benefit costs and accumulated postretirement benefit obligation. The Company provides prescription drug benefits to certain eligible employees and has elected the one-time deferral of accounting for the effects of the 2003 Medicare Act. These consolidated financial statements and accompanying notes do not reflect the effects of the 2003 Medicare Act on the postretirement benefit plans. The Company intends to analyze the 2003 Medicare Act, along with the authoritative guidance, when issued, to determine if its benefit plans need to be amended and how to record the effects of the 2003 Medicare Act. Specific guidance on the accounting for the federal subsidy provided by the 2003 Medicare Act is pending and that guidance, when issued, could require the Company to change previously reported postretirement benefit information. For more information on the Company's postretirement benefits, see Note 16. Comprehensive income Comprehensive income is the sum of net income as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains and losses on derivative instruments qualifying as hedges, minimum pension liability adjustments and foreign currency translation adjustments. The components of other comprehensive income (loss), and their related tax effects for the years ended December 31, 2003, 2002 and 2001, were as follows: 2003 2002 2001 (In thousands) Other comprehensive income (loss): Net unrealized gain (loss) on derivative instruments qualifying as hedges: Unrealized loss on derivative instruments at January 1, 2001, due to cumulative effect of a change in accounting principle, net of tax of $3,970 in 2001 $ --- $ --- $(6,080) Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $2,132, $2,903 and $1,448 in 2003, 2002 and 2001, respectively (3,335) (4,541) 2,218 Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income, net of tax of $2,903, $1,448 and $3,970 in 2003, 2002 and 2001, respectively (4,541) 2,218 (6,080) Net unrealized gain (loss) on derivative instruments qualifying as hedges 1,206 (6,759) 2,218 Minimum pension liability adjustment, net of tax of $38 and $2,876 in 2003 and 2002, respectively 21 (4,464) --- Foreign currency translation adjustment 1,048 (799) --- Total other comprehensive income (loss) $ 2,275 $(12,022) $ 2,218 The after-tax components of accumulated other comprehensive income (loss) as of December 31, 2003, 2002 and 2001, were as follows: Net Unrealized Gain (Loss) on Total Derivative Minimum Foreign Accumulated Instruments Pension Currency Other Qualifying Liability Translation Comprehensive as Hedges Adjustment Adjustment Income (Loss) (In thousands) Balance at December 31, 2001 $ 2,218 $ --- $ --- $ 2,218 Balance at December 31, 2002 $(4,541) $(4,464) $ (799) $(9,804) Balance at December 31, 2003 $(3,335) $(4,443) $ 249 $(7,529) NOTE 2 Equity Method Investments The Company has a number of equity method investments, including MPX, which was formed in August 2001 when MDU Brasil entered into a joint venture agreement with a Brazilian firm. MDU Brasil has a 49 percent interest in MPX, which is being accounted for under the equity method of accounting, as discussed in Note 1. MPX, through a wholly owned subsidiary, owns a 220-megawatt natural gas-fired electric generating facility (Brazil Generating Facility) in the Brazilian state of Ceara. At December 31, 2003, MPX has assets of approximately $109.6 million and long-term debt of approximately $86.8 million, including a loan of $20.0 million from Centennial Energy Resources International Inc, an indirect wholly owned subsidiary of the Company. Petrobras, the Brazilian state-controlled energy company, has agreed to purchase all of the capacity and market all of the Brazil Generating Facility's energy. The power purchase agreement with Petrobras expires in May 2008. Petrobras also is under contract to supply natural gas to the Brazil Generating Facility during the term of the power purchase agreement. This natural gas supply contract is renewable by a wholly owned subsidiary of MPX for an additional 13 years. The functional currency for the Brazil Generating Facility is the Brazilian real. The power purchase agreement with Petrobras contains an embedded derivative, which derives its value from an annual adjustment factor, which largely indexes the contract capacity payments to the U.S. dollar. For the year ended December 31, 2003, the Company's 49 percent share of the loss from the change in the fair value of the embedded derivative in the power purchase agreement was $11.3 million (after tax). For the year ended December 31, 2002, the Company's 49 percent share of the gain from the change in the fair value of the embedded derivative in the power purchase agreement was $13.6 million (after tax). The Company's 49 percent share of the foreign currency gain resulting from the revaluation of the Brazilian real was $2.8 million (after tax) for the year ended December 31, 2003. The Company's 49 percent share of the foreign currency loss resulting from devaluation of the Brazilian real was $9.4 million (after tax) for the year ended December 31, 2002. The Company's investment in the Brazil Generating Facility was approximately $25.2 million, including undistributed earnings of $4.6 million at December 31, 2003. The Company's investment in the Brazil Generating Facility was approximately $27.8 million at December 31, 2002. The Company's share of income from its equity method investments, including MPX, was $6.0 million, $1.3 million and $154,000 for the years ended December 31, 2003, 2002 and 2001, respectively, and was included in other income - net. NOTE 3 Goodwill and Other Intangible Assets On January 1, 2002, in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," the Company ceased amortization of its goodwill recorded in business combinations that occurred on or before June 30, 2001. The following information is presented as if SFAS No. 142 was adopted as of January 1, 2001. The reconciliation of previously reported earnings and earnings per common share to the amounts adjusted for the exclusion of goodwill amortization, net of the related income tax effects, for the years ended December 31, 2003, 2002 and 2001, were as follows: 2003 2002 2001 (In thousands, except per share amounts) Reported earnings on common stock $174,607 $147,688 $155,087 Add: Goodwill amortization, net of tax --- --- 3,649 Adjusted earnings on common stock $174,607 $147,688 $158,736 Reported earnings per common share -- basic $ 1.57 $ 1.39 $ 1.54 Add: Goodwill amortization, net of tax --- --- .03 Adjusted earnings per common share -- basic $ 1.57 $ 1.39 $ 1.57 Reported earnings per common share -- diluted $ 1.55 $ 1.38 $ 1.52 Add: Goodwill amortization, net of tax --- --- .04 Adjusted earnings per common share -- diluted $ 1.55 $ 1.38 $ 1.56 The changes in the carrying amount of goodwill for the year ended December 31, 2003, were as follows: Balance Goodwill Balance as of Acquired as of January 1, During December 31, 2003 the Year 2003 (In thousands) Electric $ --- $ --- $ --- Natural gas distribution --- --- --- Utility services 62,487 117 62,604 Pipeline and energy services 9,494 --- 9,494 Natural gas and oil production --- --- --- Construction materials and mining 111,887 8,311 120,198 Independent power production and other 7,131 --- 7,131 Total $190,999 $8,428 $199,427 The changes in the carrying amount of goodwill for the year ended December 31, 2002, were as follows: Balance Goodwill Balance as of Acquired as of January 1, During December 31, 2002 the Year 2002 (In thousands) Electric $ --- $ --- $ --- Natural gas distribution --- --- --- Utility services 61,909 578 62,487 Pipeline and energy services 9,336 158 9,494 Natural gas and oil production --- --- --- Construction materials and mining 102,752 9,135 111,887 Independent power production and other --- 7,131 7,131 Total $173,997 $17,002 $190,999 Other intangible assets at December 31, 2003 and 2002, were as follows: 2003 2002 (In thousands) Amortizable intangible assets: Leasehold rights $186,419 $172,496 Accumulated amortization (11,779) (7,494) 174,640 165,002 Noncompete agreements 12,075 12,075 Accumulated amortization (9,690) (9,366) 2,385 2,709 Other 17,734 7,224 Accumulated amortization (2,265) (374) 15,469 6,850 Unamortizable intangible assets 960 1,603 Total $193,454 $176,164 Acquired aggregate reserves at our construction materials and mining business are classified based on type of ownership. Owned mineral rights are classified as property, plant and equipment, whereas leased mineral rights are classified as leasehold rights in other intangible assets, net. The unamortizable intangible assets were recognized in accordance with SFAS No. 87, "Employers' Accounting for Pensions," which requires that if an additional minimum liability is recognized an equal amount shall be recognized as an intangible asset, provided that the asset recognized shall not exceed the amount of unrecognized prior service cost. The unamortizable intangible asset will be eliminated or adjusted as necessary upon a new determination of the amount of additional liability. Amortization expense for amortizable intangible assets for the years ended December 31, 2003 and 2002, was $5.9 million and $3.4 million, respectively. Estimated amortization expense for amortizable intangible assets is $6.2 million in 2004, $6.4 million in 2005, $5.2 million in 2006, $5.2 million in 2007, $5.2 million in 2008 and $164.3 million thereafter. SFAS No. 142 discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. SFAS No. 141, "Business Combinations," and SFAS No. 142 clarify that more assets should be distinguished and classified between tangible and intangible. The Company did not change or reclassify contractual mineral rights included in property, plant and equipment related to its natural gas and oil production business upon adoption of SFAS No. 142. The Company has included such mineral rights as part of property, plant and equipment under the full-cost method of accounting for natural gas and oil properties. An issue has arisen within the natural gas and oil industry as to whether contractual mineral rights under SFAS No. 142 should be classified as intangible rather than as part of property, plant and equipment. This accounting matter is anticipated to be addressed by the FASB's Emerging Issues Task Force. The resolution of this matter may result in certain reclassifications of amounts in the Consolidated Balance Sheets, as well as changes to Notes to Consolidated Financial Statements in the future. The applicable provisions of SFAS No. 141 and SFAS No. 142 only affect the balance sheet and associated footnote disclosure, so any reclassifications that might be required in the future will not affect the Company's cash flows or results of operations. The Company believes that the resolution of this matter will not have a material effect on the Company's financial position because the mineral rights acquired by its natural gas and oil production business after the June 30, 2001, effective date of SFAS No. 142 were not material. NOTE 4 Regulatory Assets and Liabilities The following table summarizes the individual components of unamortized regulatory assets and liabilities as of December 31: 2003 2002 (In thousands) Regulatory assets: Deferred income taxes $ 29,850 $ 27,378 Natural gas costs recoverable through rate adjustments 10,519 --- Long-term debt refinancing costs 4,519 5,627 Plant costs 2,697 2,330 Postretirement benefit costs 562 616 Other 7,159 4,788 Total regulatory assets 55,306 40,739 Regulatory liabilities: Plant removal and decommissioning costs 76,176 68,551 Reserves for regulatory matters 11,970 9,856 Taxes refundable to customers 11,751 11,699 Deferred income taxes 10,663 5,491 Natural gas costs refundable through rate adjustments --- 2,396 Other 658 2,779 Total regulatory liabilities 111,218 100,772 Net regulatory position $ (55,912) $ (60,033) As of December 31, 2003, substantially all of the Company's regulatory assets, other than certain deferred income taxes, were being reflected in rates charged to customers and are being recovered over the next one to 19 years. If, for any reason, the Company's regulated businesses cease to meet the criteria for application of SFAS No. 71 for all or part of their operations, the regulatory assets and liabilities relating to those portions ceasing to meet such criteria would be removed from the balance sheet and included in the statement of income as an extraordinary item in the period in which the discontinuance of SFAS No. 71 occurs. NOTE 5 Derivative Instruments The Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, on January 1, 2001. SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows derivative gains and losses to offset the related results on the hedged item in the income statement and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. SFAS No. 133 requires that as of the date of initial adoption, the difference between the fair market value of derivative instruments recorded on the balance sheet and the previous carrying amount of those derivative instruments be reported in net income or other comprehensive income (loss), as appropriate, as the cumulative effect of a change in accounting principle in accordance with APB Opinion No. 20, "Accounting Changes." On January 1, 2001, the Company reported a net-of-tax cumulative-effect adjustment of $6.1 million in accumulated other comprehensive loss to recognize at fair value all derivative instruments that are designated as cash flow hedging instruments, which the Company reclassified into earnings during the year ended December 31, 2001. The transition to SFAS No. 133 did not have an effect on the Company's net income at adoption. In the event a derivative instrument being accounted for as a cash flow hedge does not qualify for hedge accounting because it is no longer highly effective in offsetting changes in cash flows of a hedged item; or if the derivative instrument expires or is sold, terminated or exercised; or if management determines that designation of the derivative instrument as a hedge instrument is no longer appropriate, hedge accounting will be discontinued, and the derivative instrument would continue to be carried at fair value with changes in its fair value recognized in earnings. In these circumstances, the net gain or loss at the time of discontinuance of hedge accounting would remain in accumulated other comprehensive income (loss) until the period or periods during which the hedged forecasted transaction affects earnings, at which time the net gain or loss would be reclassified into earnings. In the event a cash flow hedge is discontinued because it is unlikely that a forecasted transaction will occur, the derivative instrument would continue to be carried on the balance sheet at its fair value, and gains and losses that had accumulated in other comprehensive income (loss) would be recognized immediately in earnings. In the event of a sale, termination or extinguishment of a foreign currency derivative, the resulting gain or loss would be recognized immediately in earnings. The Company's policy requires approval to terminate a derivative instrument prior to its original maturity. As of December 31, 2003, an indirect wholly owned subsidiary of the Company held derivative instruments designated as cash flow hedging instruments. Hedging activities The subsidiary of the Company utilizes natural gas and oil price swap and collar agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil on the subsidiary's forecasted sales of natural gas and oil production. Each of the natural gas and oil price swap and collar agreements was designated as a hedge of the forecasted sale of natural gas and oil production. On an ongoing basis, the balance sheet is adjusted to reflect the current fair market value of the swap and collar agreements. The related gains or losses on these agreements are recorded in common stockholders' equity as a component of other comprehensive income (loss). At the date the underlying transaction occurs, the amounts accumulated in other comprehensive income (loss) are reported in the Consolidated Statements of Income. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded directly in earnings. For the years ended December 31, 2003, 2002 and 2001, the subsidiary of the Company recognized the ineffectiveness of cash flow hedges, which is included in operating revenues for the natural gas and oil price swap and collar agreements. For the years ended December 31, 2003, 2002 and 2001, the amount of hedge ineffectiveness recognized was immaterial. For the years ended December 31, 2003, 2002 and 2001, the subsidiary did not exclude any components of the derivative instruments' gain or loss from the assessment of hedge effectiveness and there were no reclassifications into earnings as a result of the discontinuance of hedges. Gains and losses on derivative instruments that are reclassified from accumulated other comprehensive income (loss) to current-period earnings are included in the line item in which the hedged item is recorded. As of December 31, 2003, the maximum term of the subsidiary's swap and collar agreements, in which the subsidiary of the Company is hedging its exposure to the variability in future cash flows for forecasted transactions, is 12 months. The subsidiary of the Company estimates that over the next 12 months net losses of approximately $3.3 million will be reclassified from accumulated other comprehensive income (loss) into earnings, subject to changes in natural gas and oil market prices, as the hedged transactions affect earnings. Foreign currency derivative MDU Brasil has a 49 percent equity investment in the Brazil Generating Facility, which has a portion of its borrowings and payables denominated in U.S. dollars. MDU Brasil has exposure to currency exchange risk as a result of fluctuations in currency exchange rates between the U.S. dollar and the Brazilian real. On August 12, 2002, MDU Brasil entered into a foreign currency collar agreement for a notional amount of $21.3 million with a fixed price floor of R$3.10 and a fixed price ceiling of R$3.40 to manage a portion of its foreign currency risk. The term of the collar agreement was from August 12, 2002, through February 3, 2003, and the collar agreement settled on February 3, 2003. The foreign currency collar agreement was not designated as a hedge and was recorded at fair value on the Consolidated Balance Sheets. Gains or losses on this derivative instrument were recorded in other income - net. The Company recorded a gain of $39,000 (after tax) on the foreign currency collar agreement for the year ended December 31, 2003, and a gain of $566,000 (after tax) for the year ended December 31, 2002. Energy marketing The Company had entered into other derivative instruments that were not designated as hedges in its energy marketing operations. In the third quarter of 2001, the Company sold the vast majority of its energy marketing operations. Net unrealized gains and losses on these derivative instruments were not material for the year ended December 31, 2001. NOTE 6 Fair Value of Other Financial Instruments The estimated fair value of the Company's long-term debt and preferred stock subject to mandatory redemption is based on quoted market prices of the same or similar issues. As discussed in Note 1, the Company, upon adoption of SFAS No. 150 in 2003, began reporting its preferred stock subject to mandatory redemption as a liability. The estimated fair values of the Company's natural gas and oil price swap and collar agreements were included in current liabilities at December 31, 2003 and 2002. The estimated fair value of the Company's foreign currency collar agreement was included in current assets at December 31, 2002. The estimated fair values of the Company's natural gas and oil price swap and collar agreements and foreign currency collar agreement reflect the estimated amounts the Company would receive or pay to terminate the contracts at the reporting date based upon quoted market prices of comparable contracts. The estimated fair value of the Company's long-term debt, preferred stock subject to mandatory redemption, natural gas and oil price swap and collar agreements and foreign currency collar agreement at December 31 was as follows: 2003 2002 Carrying Fair Carrying Fair Amount Value Amount Value (In thousands) Long-term debt $967,096 $1,012,547 $841,641 $888,066 Preferred stock subject to mandatory redemption $ --- $ --- $ 1,300 $ 1,168 Natural gas and oil price swap and collar agreements $ (5,467) $ (5,467) $ (7,444) $ (7,444) Foreign currency collar agreement $ --- $ --- $ 903 $ 903 The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments) approximate their fair values because of their short-term nature. NOTE 7 Short-term Borrowings MDU Resources Group, Inc. At December 31, 2002, $8.0 million of MDU Resources Group, Inc. (MDU Resources) commercial paper program borrowings were classified as short- term borrowings. The commercial paper borrowings classified as short term were supported by short-term bank lines of credit. There were no amounts outstanding under the bank lines of credit at December 31, 2002. MDU Resources did not have any short-term bank lines of credit at December 31, 2003. For more information on MDU Resources' commercial paper program, see Note 8. International operations A subsidiary of the Company had a short-term credit agreement that expired in 2003. Under this agreement $12.0 million was outstanding at December 31, 2002. NOTE 8 Long-term Debt and Indenture Provisions Long-term debt outstanding at December 31 was as follows: 2003 2002 (In thousands) First mortgage bonds and notes: Pollution Control Refunding Revenue Bonds, Series 1992, 6.65%, due June 1, 2022 $ 20,850 $ 20,850 Secured Medium-Term Notes, Series A at a weighted average rate of 7.59%, due on dates ranging from October 1, 2004 to April 1, 2012 110,000 110,000 Senior Notes, 5.98%, due December 15, 2033 30,000 --- Total first mortgage bonds and notes 160,850 130,850 Senior notes at a weighted average rate of 6.24%, due on dates ranging from October 30, 2004 to October 30, 2018 718,000 549,100 Commercial paper at a weighted average rate of 1.12%, supported by revolving credit agreements 72,500 151,900 Term credit agreements at a weighted average rate of 5.14%, due on dates ranging from July 15, 2004 to December 1, 2013 14,286 7,873 Pollution control note obligation, 6.20%, due March 1, 2004 1,500 2,000 Discount (40) (82) Total long-term debt 967,096 841,641 Less current maturities 27,646 22,083 Net long-term debt $939,450 $819,558 The amounts of scheduled long-term debt maturities for the five years and thereafter following December 31, 2003, aggregate $27.6 million in 2004; $70.9 million in 2005; $173.2 million in 2006; $105.8 million in 2007; $160.2 million in 2008 and $429.4 million thereafter. Certain debt instruments of the Company and its subsidiaries, including those discussed below, contain restrictive covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2003. MDU Resources Group, Inc. MDU Resources has a revolving credit agreement with various banks totaling $90 million at December 31, 2003. There were no amounts outstanding under the credit agreement at December 31, 2003 and 2002. The credit agreement supports MDU Resources' $75 million commercial paper program. Under the MDU Resources' commercial paper program, $40 million was outstanding at December 31, 2003, which was classified as long-term debt, and $58.0 million was outstanding at December 31, 2002, of which $8.0 million was classified as short-term borrowings and $50.0 million was classified as long-term debt. As discussed in Note 7, the commercial paper borrowings classified as short term were supported by short-term bank lines of credit. The commercial paper borrowings classified as long-term debt are intended to be refinanced on a long- term basis through continued MDU Resources commercial paper borrowings and as further supported by the credit agreement, which expires on July 18, 2006. In order to borrow under the MDU Resources credit agreement, MDU Resources must be in compliance with the applicable covenants and certain other conditions. The significant covenants include maximum leverage ratios, minimum interest coverage ratio, limitation on sale of assets and limitation on investments. MDU Resources was in compliance with these covenants and met the required conditions at December 31, 2003. There are no credit facilities that contain cross-default provisions between MDU Resources and any of its subsidiaries. MDU Resources' 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 MDU Resources 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, 2003, MDU Resources could have issued approximately $313 million of additional first mortgage bonds. Approximately $421.2 million of the Company's net electric and natural gas distribution properties at December 31, 2003, with certain exceptions, are subject to the lien of the Indenture of Mortgage dated May 1, 1939, as supplemented, amended and restated, from the Company to The Bank of New York and Douglas J. MacInnes, successor trustee, and are subject to the junior lien of the Indenture dated as of December 15, 2003, as supplemented, from the Company to The Bank of New York, as trustee. Centennial Energy Holdings, Inc. Centennial Energy Holdings, Inc. (Centennial) has two revolving credit agreements with various banks that support $275 million of Centennial's $350 million commercial paper program. There were no outstanding borrowings under the Centennial credit agreements at December 31, 2003 or 2002. Under the Centennial commercial paper program, $32.5 million and $101.9 million were outstanding at December 31, 2003 and 2002, respectively. The Centennial commercial paper borrowings are classified as long-term debt as Centennial intends to refinance these borrowings on a long-term basis through continued Centennial commercial paper borrowings and as further supported by the Centennial credit agreements. The Centennial credit agreements are for $137.5 million each. One of these agreements expires on September 3, 2004, and allows for subsequent borrowings up to a term of one year. The other agreement expires on September 5, 2006. Centennial intends to negotiate the extension or replacement of these agreements prior to their maturities. Centennial has an uncommitted long-term master shelf agreement that allows for borrowings of up to $400 million. Under the terms of the master shelf agreement, $384.0 million was outstanding at December 31, 2003, and $360.6 million was outstanding at December 31, 2002. The amount outstanding under the uncommitted long-term master shelf agreement is included in senior notes in the preceding long-term debt table. In order to borrow under Centennial's credit agreements and the Centennial uncommitted long-term master shelf agreement, Centennial and certain of its subsidiaries must be in compliance with the applicable covenants and certain other conditions. The significant covenants include maximum capitalization ratios, minimum interest coverage ratios, minimum consolidated net worth, limitation on priority debt, limitation on sale of assets and limitation on loans and investments. Centennial and such subsidiaries were in compliance with these covenants and met the required conditions at December 31, 2003. Certain of Centennial's financing agreements contain cross-default provisions. These provisions state that if Centennial or any subsidiary of Centennial fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the applicable agreements will be in default. Certain of Centennial's financing agreements and Centennial's practice limit the amount of subsidiary indebtedness. Williston Basin Interstate Pipeline Company Williston Basin Interstate Pipeline Company (Williston Basin), an indirect wholly owned subsidiary of the Company, has an uncommitted long-term master shelf agreement that allows for borrowings of up to $100 million. Under the terms of the master shelf agreement, $55.0 million and $30.0 million was outstanding at December 31, 2003 and 2002, respectively. In order to borrow under Williston Basin's uncommitted long-term master shelf agreement, it must be in compliance with the applicable covenants and certain other conditions. The significant covenants include limitation on consolidated indebtedness, limitation on priority debt, limitation on sale of assets and limitation on investments. Williston Basin was in compliance with these covenants and met the required conditions at December 31, 2003. NOTE 9 Asset Retirement Obligations The Company adopted SFAS No. 143 on January 1, 2003, as discussed in Note 1. The Company recorded obligations related to the plugging and abandonment of natural gas and oil wells, decommissioning of certain electric generating facilities, reclamation of certain aggregate properties and certain other obligations associated with leased properties. Removal costs associated with certain natural gas distribution, transmission, storage and gathering facilities have not been recognized as these facilities have been determined to have indeterminate useful lives. Upon adoption of SFAS No. 143, the Company recorded an additional discounted liability of $22.5 million and a regulatory asset of $493,000, increased net property, plant and equipment by $9.6 million and recognized a one-time cumulative effect charge of $7.6 million (net of deferred income tax benefits of $4.8 million). The Company believes that any expenses under SFAS No. 143 as they relate to regulated operations will be recovered in rates over time and accordingly, deferred such expenses as a regulatory asset upon adoption. The Company will continue to defer those SFAS No. 143 expenses that it believes will be recovered in rates over time. In addition to the $22.5 million liability recorded upon the adoption of SFAS No. 143, the Company had previously recorded a $7.5 million liability related to retirement obligations. A reconciliation of the Company's liability for the year ended December 31 was as follows: 2003 (In thousands) Balance at January 1, 2003 $29,997 Liabilities incurred 2,405 Liabilities acquired 1,803 Liabilities settled (1,555) Accretion expense 1,906 Revisions in estimates 77 Balance at December 31, 2003 $34,633 This liability is included in other liabilities. If SFAS No. 143 had been in effect during 2002 and 2001, the Company's liability would have been approximately $30.0 million at December 31, 2002, and $27.0 million at December 31, 2001. The fair value of assets that are legally restricted for purposes of settling asset retirement obligations at December 31, 2003, was $5.1 million. NOTE 10 Preferred Stocks Preferred stocks at December 31 were as follows: 2003 2002 (Dollars in thousands) Authorized: Preferred -- 500,000 shares, cumulative, par value $100, issuable in series Preferred stock A -- 1,000,000 shares, cumulative, without par value, issuable in series (none outstanding) Preference -- 500,000 shares, cumulative, without par value, issuable in series (none outstanding) Outstanding: Subject to mandatory redemption -- Preferred -- 5.10% Series - 13,000 shares in 2002 $ --- $ 1,300 Other preferred stock -- 4.50% Series -- 100,000 shares 10,000 10,000 4.70% Series -- 50,000 shares 5,000 5,000 15,000 15,000 Total preferred stocks 15,000 16,300 Less sinking fund requirements --- 100 Net preferred stocks $15,000 $16,200 As discussed in Note 1, the Company upon adoption of SFAS No. 150 in 2003, began reporting its preferred stock subject to mandatory redemption as a liability. Restatement of prior year information is not permitted under SFAS No. 150. The 4.50% Series and 4.70% Series 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 at a redemption price, plus accrued dividends, of $105 and $102, respectively. In the event of a voluntary or involuntary liquidation, all preferred stock series holders are entitled to $100 per share, plus accrued dividends. The affirmative vote of two-thirds of a series of the Company's outstanding preferred stock is necessary for amendments to the Company's charter or by-laws that adversely affect that series; creation of or increase in the amount of authorized stock ranking senior to that series (or an affirmative majority vote where the authorization relates to a new class of stock that ranks on parity with such series); a voluntary liquidation or sale of substantially all of the Company's assets; a merger or consolidation, with certain exceptions; or the partial retirement of that series of preferred stock when all dividends on that series of preferred stock have not been paid. The consent of the holders of a particular series is not required for such corporate actions if the equivalent vote of all outstanding series of preferred stock voting together has consented to the given action and no particular series is affected differently than any other series. Subject to the foregoing, the holders of common stock exclusively possess all voting power. However, if cumulative dividends on preferred stock are in arrears, in whole or in part, for one year the holders of preferred stock would obtain the right to one vote per share until all dividends in arrears have been paid and current dividends have been declared and set aside. NOTE 11 Common Stock On August 14, 2003, the Company's Board of Directors approved a three- for-two common stock split to be effected in the form of a 50 percent common stock dividend. The additional shares of common stock were distributed on October 29, 2003, to common stockholders of record on October 10, 2003. Common stock information appearing in the accompanying consolidated financial statements has been restated to give retroactive effect to the stock split. Additionally, preference share purchase rights have been appropriately adjusted to reflect the effects of the split. At the Annual Meeting of Stockholders held on April 23, 2002, the Company's common stockholders approved an amendment to the Certificate of Incorporation increasing the authorized number of common shares from 150 million shares to 250 million shares with a par value of $1.00 per share. The Company's Dividend Reinvestment and Direct Stock Purchase Plan (Stock Purchase Plan) provides interested investors the opportunity to make optional cash investments and to reinvest all or a percentage of their cash dividends in shares of the Company's common stock. The Company's 401(k) Retirement Plan (K-Plan) is partially funded with the Company's common stock. Since January 1, 2001, the Stock Purchase Plan and K-Plan, with respect to Company stock, have been funded by the purchase of shares of common stock on the open market. At December 31, 2003, there were 12.1 million shares of common stock reserved for original issuance under the Stock Purchase Plan and K-Plan. In November 1998, the Company's Board of Directors declared, pursuant to a stockholders' rights plan, a dividend of one preference share purchase right (right) for each outstanding share of the Company's common stock. Each right becomes exercisable, upon the occurrence of certain events, for two-thirds of one one-thousandth of a share of Series B Preference Stock of the Company, without par value, at an exercise price of $125, 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 15 percent or more of the Company's common stock or commences a tender or exchange offer that would result in ownership of 15 percent or more. In the event the Company is acquired in a merger or other business combination transaction or 50 percent or more of its consolidated assets or earnings power are sold, each right entitles the holder to receive, upon the exercise thereof at the then current exercise price of the right multiplied by the number of two-thirds of one one-thousandth of a Series B Preference Stock for which a right is then exercisable, in accordance with the terms of the rights agreement, such number of shares of common stock of the acquiring person having a market value of twice the then current exercise price of the right. The rights, which expire on December 31, 2008, are redeemable in whole, but not in part, for a price of $.00667 per right, at the Company's option at any time until any acquiring person has acquired 15 percent or more of the Company's common stock. NOTE 12 Stock-based Compensation The Company has stock option plans for directors, key employees and employees. In 2003, the Company adopted the fair value recognition provisions of SFAS No. 123 and began expensing the fair market value of stock options for all awards granted on or after January 1, 2003. As permitted by SFAS No. 148, the Company accounts for stock options granted prior to January 1, 2003, under APB Opinion No. 25. For a discussion of the adoption of SFAS No. 123 and the effect on earnings and earnings per common share for the years ended December 31, 2003, 2002 and 2001, as if the Company had applied SFAS No. 123, and recognized compensation expense for all outstanding and unvested stock options based on the fair value at the date of grant, see Note 1. Options granted to key employees automatically vest after nine years, but the plan provides for accelerated vesting based on the attainment of certain performance goals or upon a change in control of the Company, and expire 10 years after the date of grant. Options granted to directors and employees vest at date of grant and three years after date of grant, respectively, and expire 10 years after the date of grant. A summary of the status of the stock option plans at December 31, 2003, 2002 and 2001, and changes during the years then ended was as follows: 2003 2002 2001 Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price Balance at beginning of year 4,861,268 $18.58 5,208,311 $18.60 1,837,439 $13.74 Granted 27,015 17.29 160,605 19.15 4,039,680 20.09 Forfeited (188,486) 20.05 (453,840) 19.77 (111,423) 18.16 Exercised (517,341) 13.88 (53,808) 12.20 (557,385) 13.49 Balance at end of year 4,182,456 19.09 4,861,268 18.58 5,208,311 18.60 Exercisable at end of year 611,404 $15.06 1,135,050 $14.56 1,155,213 $14.27 Summarized information about stock options outstanding and exercisable as of December 31, 2003, was as follows: Options Outstanding Options Exercisable Remaining Weighted Weighted Contractual Average Average Range of Number Life Exercise Number Exercise Exercisable Prices Outstanding in Years Price Exercisable Price $ 8.22 - 13.00 23,451 2.5 $ 9.77 23,451 $ 9.77 13.01 - 17.00 647,085 4.3 14.13 511,453 14.15 17.01 - 21.00 3,302,115 7.2 19.77 36,000 19.54 21.01 - 25.70 209,805 7.2 24.56 40,500 25.70 Balance at end of year 4,182,456 6.7 19.09 611,404 15.06 The fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model. The weighted average fair value of the options granted and the assumptions used to estimate the fair value of options were as follows: 2003 2002 2001 Weighted average fair value of options at grant date $4.67 $5.38 $4.92 Weighted average risk-free interest rate 3.91% 5.14% 5.19% Weighted average expected price volatility 32.28% 30.80% 26.05% Weighted average expected dividend yield 3.43% 3.43% 3.53% Expected life in years 7 7 7 In addition, the Company granted restricted stock awards under a long- term incentive plan and deferred compensation agreements totaling 525,588 shares in 2001. The restricted stock awards granted vest to the participants at various times ranging from two years to nine years from date of issuance, but certain grants may vest early based upon the attainment of certain performance goals or upon a change in control of the Company. The weighted average grant date fair value of the restricted stock grant in 2001 was $21.03. The Company also has granted stock awards totaling 31,855 shares, 21,390 shares and 19,009 shares in 2003, 2002 and 2001, respectively, under a nonemployee director stock compensation plan. The weighted average grant date fair value of the stock grants was $21.40, $19.20 and $20.09, in 2003, 2002 and 2001, respectively. Nonemployee directors may receive shares of common stock instead of cash in payment for directors' fees under the nonemployee director stock compensation plan. Compensation expense recognized for restricted stock grants and stock grants was $4.8 million, $5.2 million and $4.9 million in 2003, 2002 and 2001, respectively. In 2003, key employees of the Company were awarded performance share awards. Entitlement to performance shares is based on the Company's total shareholder return over designated performance periods as measured against a selected peer group. Target grants of performance shares were made for the following performance periods: Target Grant Grant Date Performance Period of Shares February 2003 2003-2004 57,655 February 2003 2003-2005 57,655 Participants may earn additional performance shares if the Company's total shareholder return exceeds that of the selected peer group. The final value of the performance units may vary according to the number of shares of Company stock that are ultimately granted based on the performance criteria. Compensation expense recognized for the performance share awards for the year ended December 31, 2003, was $879,000. The Company is authorized to grant options, restricted stock and stock for up to 14.3 million shares of common stock and has granted options, restricted stock and stock on 6.2 million shares through December 31, 2003. NOTE 13 Income Taxes Income tax expense for the years ended December 31 was as follows: 2003 2002 2001 (In thousands) Current: Federal $26,313 $46,389 $66,211 State 7,408 9,082 11,160 Foreign 264 --- (44) 33,985 55,471 77,327 Deferred: Income taxes -- Federal 55,660 26,373 16,972 State 9,861 4,632 4,773 Foreign (338) 338 --- Investment tax credit (596) (584) (731) 64,587 30,759 21,014 Total income tax expense $98,572 $86,230 $98,341 Components of deferred tax assets and deferred tax liabilities recognized at December 31 were as follows: 2003 2002 (In thousands) Deferred tax assets: Regulatory matters $ 37,072 $ 34,792 Accrued pension costs 12,122 12,112 Deferred compensation 9,090 6,395 Asset retirement obligations 7,017 263 Bad debts 3,188 2,798 Deferred investment tax credit 954 1,185 Other 21,269 18,444 Total deferred tax assets 90,712 75,989 Deferred tax liabilities: Depreciation and basis differences on property, plant and equipment 406,589 354,842 Basis differences on natural gas and oil producing properties 105,826 70,464 Regulatory matters 10,663 5,491 Other 9,309 10,412 Total deferred tax liabilities 532,387 441,209 Net deferred income tax liability $(441,675) $(365,220) As of December 31, 2003 and 2002, no valuation allowance has been recorded associated with the above deferred tax assets. The following table reconciles the change in the net deferred income tax liability from December 31, 2002, to December 31, 2003, to deferred income tax expense: 2003 (In thousands) Net change in deferred income tax liability from the preceding table $ 76,455 Deferred taxes associated with acquisitions (15,056) Deferred taxes associated with the cumulative effect of accounting change 4,821 Deferred taxes associated with other comprehensive income (809) Other (824) Deferred income tax expense for the period $ 64,587 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 were as follows: Years ended December 31, 2003 2002 2001 Amount % Amount % Amount % (Dollars in thousands) Computed tax at federal statutory rate $98,520 35.0 $82,136 35.0 $88,966 35.0 Increases (reductions) resulting from: State income taxes, net of federal income tax benefit 11,857 4.2 10,279 4.4 11,311 4.5 Investment tax credit amortization (596) (.2) (584) (.3) (731) (.3) Depletion allowance (3,117) (1.1) (2,200) (.9) (1,820) (.7) Renewable electricity production credit (3,395) (1.2) --- --- --- --- Other items (4,697) (1.7) (3,401) (1.5) 615 .2 Total income tax expense $98,572 35.0 $86,230 36.7 $98,341 38.7 The Company considers earnings from its foreign equity method investment in a natural gas-fired electric generating facility in Brazil to be reinvested indefinitely outside of the United States and, accordingly, no U.S. deferred income taxes are recorded with respect to such earnings. Should the earnings be remitted as dividends, the Company may be subject to additional U.S. taxes, net of allowable foreign tax credits. NOTE 14 Business Segment Data The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The Company has six reportable segments consisting of electric, natural gas distribution, utility services, pipeline and energy services, natural gas and oil production, and construction materials and mining. During the fourth quarter of 2002, the Company separated independent power production and other operations from its reportable segments. The independent power production and other operations do not individually meet the criteria to be considered a reportable segment. Substantially all of the operations of independent power production and other began in 2002; therefore, financial information for years prior to 2002 has not been presented. The vast majority of the Company's operations are located within the United States. The Company also has investments in foreign countries, which largely consist of an investment in a natural gas-fired electric generating facility in Brazil, as discussed in Note 2. The electric segment generates, transmits and distributes electricity, and the natural gas distribution segment distributes natural gas. These operations also supply related value-added products and services in the northern Great Plains. The utility services segment specializes in electrical line construction, pipeline construction, inside electrical wiring and cabling and the manufacture and distribution of specialty equipment. The pipeline and energy services segment provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems primarily in the Rocky Mountain and northern Great Plains regions of the United States. The pipeline and energy services segment also provides energy-related management services, including cable and pipeline magnetization and locating. The natural gas and oil production segment is engaged in natural gas and oil acquisition, exploration and production activities, primarily in the Rocky Mountain region of the United States and in and around the Gulf of Mexico. The construction materials and mining segment mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ready-mixed concrete, cement, asphalt and other value-added products, as well as performs integrated construction services, in the central and western United States and in the states of Alaska and Hawaii. The independent power production and other operations own electric generating facilities in the United States and have an investment in an electric generating facility in Brazil. Electric capacity and energy produced at these facilities are primarily sold under long-term contracts to nonaffiliated entities. These operations also include investments in opportunities that are not directly being pursued by the Company's other businesses. In 2001, the Company sold its coal operations to Westmoreland Coal Company for $28.2 million in cash and recorded a gain of $10.3 million ($6.2 million after tax) included in other income - net. The sale of the Company's coal operations included active coal mines in North Dakota and Montana, coal sales agreements, reserves and mining equipment, and certain development rights at the Company's former Gascoyne Mine site in North Dakota. The Company retained ownership of lignite deposits and leases at its former Gascoyne Mine site in North Dakota, which were not part of the sale of the coal operations. The Gascoyne Mine site was closed in 1995 due to the cancellation of the coal sale contract. These lignite deposits are currently not being mined and are not associated with an operating mine. These lignite deposits are of a high moisture content and it is not economical to mine and ship the lignite to other distant markets. However, should a power plant be constructed near the area, the Company may have the opportunity to participate in supplying lignite to fuel a plant. As of December 31, 2003, Knife River had under ownership or lease, deposits of approximately 26.9 million tons of recoverable lignite coal. The information below follows the same accounting policies as described in the Summary of Significant Accounting Policies. Information on the Company's businesses as of December 31 and for the years then ended was as follows: 2003 2002 2001 (In thousands) External operating revenues: Electric $ 178,562 $ 162,616 $ 168,837 Natural gas distribution 274,608 186,569 255,389 Pipeline and energy services 187,892 110,224 479,108 641,062 459,409 903,334 Utility services 434,177 458,660 364,746 Natural gas and oil production 140,281 148,158 148,653 Construction materials and mining 1,104,408 962,312 806,899(a) Independent power production and other 32,261 2,998 --- 1,711,127 1,572,128 1,320,298 Total external operating revenues $2,352,189 $2,031,537 $2,223,632 Intersegment operating revenues: Electric $ --- $ --- $ --- Natural gas distribution --- --- --- Utility services --- --- 4 Pipeline and energy services 64,300 55,034 52,006 Natural gas and oil production 124,077 55,437 61,178 Construction materials and mining --- --- --- Independent power production and other 2,728 3,778 --- Intersegment eliminations (191,105) (114,249) (113,188) Total intersegment operating revenues $ --- $ --- $ --- Depreciation, depletion and amortization: Electric $ 20,150 $ 19,537 $ 19,488 Natural gas distribution 10,044 9,940 9,337 Utility services 10,353 9,871 8,395 Pipeline and energy services 15,016 14,846 14,341 Natural gas and oil production 61,019 48,714 41,690 Construction materials and mining 63,601 54,334 46,666 Independent power production and other 8,154 719 --- Total depreciation, depletion and amortization $ 188,337 $ 157,961 $ 139,917 Interest expense: Electric $ 8,013 $ 7,621 $ 8,531 Natural gas distribution 3,936 4,364 3,727 Utility services 3,668 3,568 3,807 Pipeline and energy services 7,952 7,670 9,136 Natural gas and oil production 4,767 2,464 1,359 Construction materials and mining 18,747 18,422 19,339 Independent power production and other 5,865 1,122 --- Intersegment eliminations (154) (216) --- Total interest expense $ 52,794 $ 45,015 $ 45,899 Income taxes: Electric $ 9,862 $ 9,501 $ 10,511 Natural gas distribution 1,823 (1,325) 1,067 Utility services 3,905 4,781 9,131 Pipeline and energy services 11,188 12,462 11,633 Natural gas and oil production 42,993 30,604 40,486 Construction materials and mining 28,168 29,415 25,513 Independent power production and other 633 792 --- Total income taxes $ 98,572 $ 86,230 $ 98,341 Cumulative effect of accounting change (Note 9): Electric $ --- $ --- $ --- Natural gas distribution --- --- --- Utility services --- --- --- Pipeline and energy services --- --- --- Natural gas and oil production (7,740) --- --- Construction materials and mining 151 --- --- Independent power production and other --- --- --- Total cumulative effect of accounting change $ (7,589) $ --- $ --- Earnings on common stock: Electric $ 16,950 $ 15,780 $ 18,717 Natural gas distribution 3,869 3,587 677 Utility services 6,170 6,371 12,910 Pipeline and energy services 18,158 19,097 16,406 Natural gas and oil production 63,027 53,192 63,178 Construction materials and mining 54,412 48,702 43,199 Independent power production and other 12,021 959 --- Total earnings on common stock $ 174,607 $ 147,688 $ 155,087 Capital expenditures: Electric $ 28,537 $ 27,795 $ 14,373 Natural gas distribution 15,672 11,044 14,685 Utility services 7,820 17,242 70,232 Pipeline and energy services 93,004 21,449 51,054 Natural gas and oil production 101,698 136,424 118,719 Construction materials and mining 128,487 106,893 170,585 Independent power production and other 112,858 95,748 --- Net proceeds from sale or disposition of property (14,439) (16,217) (51,641) Total net capital expenditures $ 473,637 $ 400,378 $ 388,007 Identifiable assets: Electric(b) $ 327,899 $ 322,475 $ 301,982 Natural gas distribution(b) 234,948 208,502 217,402 Utility services 221,824 230,888 239,069 Pipeline and energy services 405,904 312,858 354,336 Natural gas and oil production 602,389 554,420 476,105 Construction materials and mining 1,248,607 1,137,697 1,035,929 Independent power production and other 263,941 148,770 --- Corporate assets(c) 75,080 81,311 51,155 Total identifiable assets $3,380,592 $2,996,921 $2,675,978 Property, plant and equipment: Electric(b) $ 639,893 $ 619,230 $ 597,080 Natural gas distribution(b) 252,591 244,930 235,771 Utility services 76,871 70,660 59,190 Pipeline and energy services 461,793 372,420 369,775 Natural gas and oil production 871,357 755,788 630,826 Construction materials and mining 893,980 804,255 711,410 Independent power production and other 201,134 94,525 --- Less accumulated depreciation, depletion and amortization 1,175,326 1,019,438 889,816 Net property, plant and equipment $2,222,293 $1,942,370 $1,714,236 (a) In accordance with the provision of SFAS No. 71, intercompany coal sales of $5,016 in 2001 were not eliminated. (b) Includes allocations of common utility property. (c) Corporate assets consist of assets not directly assignable to a business (i.e., cash and cash equivalents, certain accounts receivable and other miscellaneous current and deferred assets). Earnings from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings from utility services, natural gas and oil production, construction materials and mining, and independent power production and other are all from nonregulated operations. Capital expenditures for 2003, 2002 and 2001, related to acquisitions, in the preceding table included the following noncash transactions: issuance of the Company's equity securities of $42.4 million, $47.2 million and $57.4 million in 2003, 2002 and 2001, respectively. NOTE 15 Acquisitions In 2003, the Company acquired a number of businesses, none of which was individually material, including construction materials and mining businesses in Montana, North Dakota and Texas and a wind-powered electric generation facility in California. The total purchase consideration for these businesses and adjustments with respect to certain other acquisitions acquired in 2002, including the Company's common stock and cash, was $175.0 million. In 2002, the Company acquired a number of businesses, none of which was individually material, including utility services companies in California and Ohio, construction materials and mining businesses in Minnesota and Montana, an energy development company in Montana and natural gas-fired electric generating facilities in Colorado. The total purchase consideration for these businesses, consisting of the Company's common stock and cash, was $139.8 million. In 2001, the Company acquired a number of businesses, none of which was individually material, including construction materials and mining businesses in Hawaii, Minnesota and Oregon; utility services businesses based in Missouri and Oregon; and an energy services company specializing in cable and pipeline locating and tracking systems. The total purchase consideration for these businesses, consisting of the Company's common stock and cash, was $170.1 million. On April 1, 2000, Fidelity Exploration & Production Company (Fidelity), an indirect wholly owned subsidiary of the Company, purchased substantially all of the assets of Preston Reynolds & Co., Inc. (Preston), a coalbed natural gas development operation based in Colorado with related oil and gas leases and properties in Montana and Wyoming. Pursuant to the asset purchase and sale agreement, Preston could, but was not obligated to purchase, acquire and own an undivided 25 percent working interest (Seller's Option Interest) in certain oil and gas leases or properties acquired and/or generated by Fidelity. Fidelity had the right, but not the obligation, to purchase Seller's Option Interest from Preston for an amount as specified in the agreement. On July 10, 2002, Fidelity purchased the Seller's Option Interest. The above acquisitions were accounted for under the purchase method of accounting and, accordingly, the acquired assets and liabilities assumed have been preliminarily recorded at their respective fair values as of the date of acquisition. Final fair market values are pending the completion of the review of the relevant assets, liabilities and issues identified as of the acquisition date on certain of the above acquisitions made in 2003. The results of operations of the acquired businesses are included in the financial statements since the date of each acquisition. Pro forma financial amounts reflecting the effects of the above acquisitions are not presented, as such acquisitions were not material to the Company's financial position or results of operations. NOTE 16 Employee Benefit Plans The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. The Company uses a measurement date of December 31 for all of its pension and postretirement benefit plans. These financial statements and this Note do not reflect the effects of the 2003 Medicare Act on the postretirement benefit plans. For more information on the 2003 Medicare Act, see new accounting standards in Note 1. Changes in benefit obligation and plan assets for the years ended December 31 and amounts recognized in the Consolidated Balance Sheets at December 31 were as follows: Other Pension Postretirement Benefits Benefits 2003 2002 2003 2002 (In thousands) Change in benefit obligation: Benefit obligation at beginning of year $224,766 $204,046 $74,917 $67,019 Service cost 5,897 5,135 1,857 1,460 Interest cost 15,211 14,877 5,281 4,915 Plan participants' contributions --- --- 977 834 Amendments 210 372 754 --- Actuarial loss 27,701 12,324 10,338 5,678 Benefits paid (12,450) (11,988) (5,743) (4,989) Benefit obligation at end of year 261,335 224,766 88,381 74,917 Change in plan assets: Fair value of plan assets at beginning of year 189,143 224,667 40,889 45,175 Actual gain (loss) on plan assets 43,087 (26,543) 6,148 (4,196) Employer contribution 3,263 3,007 4,963 4,065 Plan participants' contributions --- --- 977 834 Benefits paid (12,450) (11,988) (5,743) (4,989) Fair value of plan assets at end of year 223,043 189,143 47,234 40,889 Funded status - over (under) (38,292) (35,623) (41,147) (34,028) Unrecognized actuarial loss 41,422 35,662 11,862 3,484 Unrecognized prior service cost 8,556 9,501 706 --- Unrecognized net transition obligation (asset) (297) (1,247) 19,362 21,513 Prepaid (accrued) benefit cost $ 11,389 $ 8,293 $(9,217) $(9,031) Amounts recognized in the Consolidated Balance Sheets at December 31: Prepaid benefit cost $ 19,671 $ 16,175 $ 614 $ 780 Accrued benefit liability (8,282) (7,882) (9,831) (9,811) Additional minimum liability --- (4,905) --- --- Intangible asset --- 533 --- --- Accumulated other comprehensive loss --- 4,372 --- --- Net amount recognized $ 11,389 $ 8,293 $(9,217) $(9,031) Employer contributions and benefits paid in the above table include only those amounts contributed directly to, or paid directly from, plan assets. The accumulated benefit obligation for the defined benefit pension plans reflected above was $212.0 million and $186.4 million at December 31, 2003 and 2002, respectively. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets at December 31, 2003, were as follows: 2003 2002 (In thousands) Projected benefit obligation $38,845 $32,768 Accumulated benefit obligation $28,840 $24,656 Fair value of plan assets $24,508 $20,615 Components of net periodic benefit cost (income) for the Company's pension and other postretirement benefit plans were as follows: Other Pension Postretirement Benefits Benefits Years ended December 31, 2003 2002 2001 2003 2002 2001 (In thousands) Components of net periodic benefit cost: Service cost $ 5,897 $ 5,135 $ 4,716 $ 1,857 $ 1,460 $ 1,376 Interest cost 15,211 14,877 14,498 5,281 4,915 4,691 Expected return on assets (20,730) (21,110) (20,672) (3,933) (3,843) (3,619) Amortization of prior service cost 1,156 1,148 1,247 48 --- --- Recognized net actuarial gain (417) (1,855) (2,687) (255) (566) (930) Settlement (gain) loss --- --- (884) --- --- 15 Amortization of net transition obligation (asset) (950) (947) (965) 2,151 2,151 2,227 Net periodic benefit cost (income) 167 (2,752) (4,747) 5,149 4,117 3,760 Less amount capitalized 14 (352) (391) 601 404 329 Net periodic benefit cost (income) $ 153 $(2,400) $(4,356) $ 4,548 $ 3,713 $ 3,431 Weighted average assumptions used to determine benefit obligations at December 31 were as follows: Other Pension Postretirement Benefits Benefits 2003 2002 2003 2002 Discount rate 6.00% 6.75% 6.00% 6.75% Rate of compensation increase 4.70% 4.50% 4.50% 4.50% Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31 were as follows: Other Pension Postretirement Benefits Benefits 2003 2002 2003 2002 Discount rate 6.75% 7.25% 6.75% 7.25% Expected return on plan assets 8.50% 8.50% 7.50% 7.50% Rate of compensation increase 4.50% 5.00% 4.50% 5.00% The expected rate of return on plan assets is based on the targeted asset allocation of 70 percent equity securities and 30 percent fixed income securities and the expected rate of return from these asset categories. The expected return on plan assets for other postretirement benefits reflects insurance-related investment costs. Health care rate assumptions for the Company's other postretirement benefit plans as of December 31 were as follows: 2003 2002 Health care trend rate assumed for next year 6.0%-9.5% 6.0%-11.0% Health care cost trend rate - ultimate 5.0%-6.0% 5.0%-6.0% Year in which ultimate trend rate achieved 1999-2012 1999-2011 The Company's other postretirement benefit plans include health care and life insurance benefits for certain employees. 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 plans anticipates future cost-sharing changes that are consistent with the Company's expressed intent to generally increase retiree contributions each year by the excess of the expected health care cost trend rate over 6 percent. Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed health care cost trend rates would have had the following effects at December 31, 2003: 1 Percentage 1 Percentage Point Increase Point Decrease (In thousands) Effect on total of service and interest cost components $ 250 $ (972) Effect on postretirement benefit obligation $3,479 $(9,554) The Company's defined benefit pension plans asset allocation at December 31, 2003 and 2002, and weighted average targeted asset allocations at December 31, 2003, were as follows: Weighted Average Percentage Targeted Asset of Plan Allocation Assets Percentage Asset Category 2003 2002 2003 Equity securities 72% 56% 70% Fixed income securities 25 40 30* Other 3 4 --- Total 100% 100% 100% *Includes target for both fixed income securities and other. The Company's pension assets are managed by nine outside investment managers. The Company's other postretirement assets are managed by one outside investment manager. The Company's investment policy with respect to pension and other postretirement assets is to make investments solely in the interest of the participants and beneficiaries of the plans and for the exclusive purpose of providing benefits accrued and defraying the reasonable expenses of administration. The Company strives to maintain investment diversification to assist in minimizing the risk of large losses. The Company's policy guidelines allow for investment of funds in cash equivalents, fixed income securities and equity securities. The guidelines prohibit investment in commodities and future contracts, equity private placement, employer securities and leveraged or derivative securities. The guidelines also prohibit short selling and margin transactions. The Company's practice is to periodically review and rebalance asset categories based on its targeted asset allocation percentage policy. The Company's other postretirement benefit plans asset allocation at December 31, 2003 and 2002, and weighted average targeted asset allocation at December 31, 2003, were as follows: Weighted Average Percentage Targeted Asset of Plan Allocation Assets Percentage Asset Category 2003 2002 2003 Equity securities 66% 50% 70% Fixed income securities 30 45 30* Other 4 5 --- Total 100% 100% 100% *Includes target for both fixed income securities and other. The Company expects to contribute approximately $1.6 million to its defined benefit pension plans and approximately $5.0 million to its postretirement benefit plans in 2004. In addition to company-sponsored plans, certain employees are covered under multi-employer defined benefit plans administered by a union. Amounts contributed to the multi-employer plans were $27.2 million, $27.8 million and $19.9 million in 2003, 2002 and 2001, respectively. In addition to the qualified plan defined pension benefits reflected in the table at the beginning of Note 16, the Company also 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 or as an equivalent life annuity. Investments consist of life insurance carried on plan participants, which is payable to the Company upon the employee's death. The cost of these benefits was $5.3 million, $5.1 million and $4.3 million in 2003, 2002 and 2001, respectively. The total projected obligation for this plan was $51.1 million and $40.5 million at December 31, 2003 and 2002, respectively. The accumulated benefit obligation for this plan was $40.7 million and $33.3 million at December 31, 2003 and 2002, respectively. The additional minimum liability relating to this plan was $8.2 million and $4.0 million at December 31, 2003 and 2002, respectively. The Company has a related intangible asset recognized as of December 31, 2003 and 2002, of $1.0 million and $1.1 million, respectively. A discount rate of 6.0 percent and 6.75 percent at December 31, 2003 and 2002, respectively, and a rate of compensation increase of 4.75 percent and 4.50 percent at December 31, 2003 and 2002, respectively, were used to determine benefit obligations. A discount rate of 6.75 percent and 7.25 percent at December 31, 2003 and 2002, respectively, and a rate of compensation increase of 4.50 percent and 5.00 percent at December 31, 2003 and 2002, respectively, were used to determine net periodic benefit cost. The increase in minimum liability included in other comprehensive income was $2.6 million in 2003 and $1.8 million in 2002. The Company sponsors various defined contribution plans for eligible employees. Costs incurred by the Company under these plans were $9.8 million in 2003, $9.6 million in 2002 and $7.2 million in 2001. The costs incurred in each year reflect additional participants as a result of business acquisitions. NOTE 17 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 financing its investment in the jointly owned facilities. The Company's share of the Big Stone Station and Coyote Station operating expenses was 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: 2003 2002 (In thousands) Big Stone Station: Utility plant in service $ 52,154 $ 53,018 Less accumulated depreciation 34,993 34,456 $ 17,161 $ 18,562 Coyote Station: Utility plant in service $124,086 $122,476 Less accumulated depreciation 72,850 70,778 $ 51,236 $ 51,698 NOTE 18 Regulatory Matters and Revenues Subject To Refund On May 30, 2003, Montana-Dakota Utilities Co. (Montana-Dakota), a public utility division of MDU Resources, filed an application with the North Dakota Public Service Commission (NDPSC) for an electric rate increase. Montana-Dakota requested a total of $7.8 million annually or 9.1 percent above current rates. On July 23, 2003, Montana-Dakota and the NDPSC Staff filed a Settlement Agreement with the NDPSC agreeing on the issues of rate of return, capital structure and cost of capital components. On October 22, 2003, the NDPSC approved the Settlement Agreement. On November 19, 2003, Montana-Dakota and the NDPSC Staff filed an additional Settlement Agreement to resolve all remaining outstanding issues with the NDPSC. This Settlement Agreement reflected an increase of $1.0 million annually and a sharing mechanism between Montana-Dakota and retail customers of wholesale electric sales margins. On December 18, 2003, the NDPSC approved the November 2003 Settlement Agreement and required Montana-Dakota to file a compliance filing with the NDPSC. On January 14, 2004, the NDPSC approved Montana- Dakota's compliance filing, which was filed on January 7, 2004, with rates effective with service rendered on and after January 23, 2004. In December 2002, Montana-Dakota filed an application with the South Dakota Public Utilities Commission (SDPUC) for a natural gas rate increase. Montana-Dakota requested a total of $2.2 million annually or 5.8 percent above current rates. On October 27, 2003, Montana-Dakota and the SDPUC Staff filed a Settlement Stipulation with the SDPUC agreeing to an increase of $1.3 million annually. On December 2, 2003, the SDPUC approved the Settlement Stipulation effective with service rendered on and after December 2, 2003. In October 2002, Great Plains Natural Gas Co. (Great Plains), a public utility division of MDU Resources, filed an application with the Minnesota Public Utilities Commission (MPUC) for a natural gas rate increase. Great Plains requested a total of $1.6 million annually or 6.9 percent above current rates. In December 2002, the MPUC issued an Order setting interim rates that approved an interim increase of $1.4 million annually effective December 6, 2002. Great Plains began collecting such rates effective December 6, 2002, subject to refund until the MPUC issued a final order. On October 9, 2003, the MPUC issued a Final Order authorizing an increase of $1.1 million annually and requiring Great Plains to file a compliance filing with the MPUC. On January 16, 2004, the MPUC issued an Order accepting Great Plains' compliance filing, which was filed on November 10, 2003, effective with service rendered on and after January 16, 2004. Reserves have been provided for a portion of the revenues that have been collected subject to refund for certain of the above proceedings. The Company believes that such reserves are adequate based on its assessment of the ultimate outcome of the proceedings. In December 1999, Williston Basin filed a general natural gas rate change application with the FERC. Williston Basin began collecting such rates effective June 1, 2000, subject to refund. In May 2001, the Administrative Law Judge (ALJ) issued an Initial Decision on Williston Basin's natural gas rate change application. The Initial Decision addressed numerous issues relating to the rate change application, including matters relating to allowable levels of rate base, return on common equity, and cost of service, as well as volumes established for purposes of cost recovery, and cost allocation and rate design. On July 3, 2003, the FERC issued its Order on Initial Decision. The Order on Initial Decision affirmed the ALJ's Initial Decision on many of the issues including rate base and certain cost of service items as well as volumes to be used for purposes of cost recovery, and cost allocation and rate design. However, there are other issues as to which the FERC differed with the ALJ including return on common equity and the correct level of corporate overhead expense. On August 4, 2003, Williston Basin requested a rehearing of a number of issues including determinations associated with cost of service, throughput, and cost allocation and rate design, as discussed in the FERC's Order on Initial Decision. On September 3, 2003, the FERC issued an Order granting Williston Basin's request for rehearing of the July 3, 2003, Order on Initial Decision. The Company is awaiting a decision from the FERC on the merits of the Company's rehearing request and is unable to predict the timing of the FERC's decision. Reserves have been provided for a portion of the revenues that have been collected subject to refund with respect to Williston Basin's pending regulatory proceeding. Williston Basin believes that such reserves are adequate based on its assessment of the ultimate outcome of the proceeding. NOTE 19 Commitments and Contingencies Litigation In January 2002, Fidelity Oil Co. (FOC), one of the Company's natural gas and oil production subsidiaries, entered into a compromise agreement with the former operator of certain of FOC's oil production properties in southeastern Montana. The compromise agreement resolved litigation involving the interpretation and application of contractual provisions regarding net proceeds interests paid by the former operator to FOC for a number of years prior to 1998. The terms of the compromise agreement are confidential. As a result of the compromise agreement, the natural gas and oil production segment reflected a nonrecurring gain in its financial results for the first quarter of 2002 of approximately $16.6 million after tax. As part of the settlement, FOC gave the former operator a full and complete release, and FOC is not asserting any such claim against the former operator for periods after 1997. In June 1997, Jack J. Grynberg (Grynberg) filed a Federal False Claims Act suit against Williston Basin and Montana-Dakota and filed over 70 similar suits against natural gas transmission companies and producers, gatherers, and processors of natural gas. Grynberg, acting on behalf of the United States under the Federal False Claims Act, alleged improper measurement of the heating content and volume of natural gas purchased by the defendants resulting in the underpayment of royalties to the United States. In April 1999, the United States Department of Justice decided not to intervene in these cases. In response to a motion filed by Grynberg, the Judicial Panel on Multidistrict Litigation consolidated all of these cases in the Federal District Court of Wyoming. The matter is currently in the discovery stage. Grynberg has not specified the amount he seeks to recover. Williston Basin and Montana- Dakota are unable to estimate their potential exposure and will be unable to do so until discovery is completed. Williston Basin and Montana-Dakota believe that the Grynberg case will ultimately be dismissed because Grynberg is not, as is required by the Federal False Claims Act, the original source of the information underlying the action. Failing this, Williston Basin and Montana-Dakota believe Grynberg will not recover damages from Williston Basin and Montana- Dakota because insufficient facts exist to support the allegations. Williston Basin and Montana-Dakota believe the claims of Grynberg are without merit and intend to vigorously contest this suit. Williston Basin and Montana-Dakota believe it is not probable that Grynberg will ultimately succeed given the current status of the litigation. Fidelity has been named as a defendant in, and/or certain of its operations are the subject of, 11 lawsuits filed in connection with its coalbed natural gas development in the Powder River Basin in Montana and Wyoming. These lawsuits were filed in federal and state courts in Montana between June 2000 and December 2003 by a number of environmental organizations, including the Northern Plains Resource Council and the Montana Environmental Information Center as well as the Tongue River Water Users' Association and the Northern Cheyenne Tribe. Two of the lawsuits have been transferred to Federal District Court in Wyoming. The lawsuits involve allegations that Fidelity and/or various government agencies are in violation of state and/or federal law, including the Federal Clean Water Act and the National Environmental Policy Act. The lawsuits seek injunctive relief, invalidation of various permits and unspecified damages. Fidelity is unable to quantify the damages sought, and will be unable to do so until after completion of discovery. Fidelity is vigorously defending all coalbed- related lawsuits in which it is involved. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could have a material effect on Fidelity's existing coalbed natural gas operations and/or the future development of its coalbed natural gas properties. Montana-Dakota has joined with two electric generators in appealing a finding by the North Dakota Department of Health (Department) in September 2003 that the Department may unilaterally revise operating permits previously issued to electric generating plants. Although it is doubtful that any revision of Montana-Dakota's operating permits by the Department would reduce the amount of electricity its plants could generate, the finding, if allowed to stand, could increase costs for sulfur dioxide removal and/or limit Montana-Dakota's ability to modify or expand operations at its North Dakota generation sites. Montana- Dakota and the other electric generators filed their appeal of the order on October 8, 2003, in the Burleigh County District Court in Bismarck, North Dakota. Proceedings have been stayed pending discussions with the United States Environmental Protection Agency (EPA), the Department and the other electric generators. In a related case, the Dakota Resource Council filed an action in Federal District Court in Denver, Colorado, on September 30, 2003, to require the EPA to enforce certain air quality standards in North Dakota. If successful, the action could require the curtailment of discharges of sulfur dioxide into the atmosphere by existing electric generating facilities and could preclude or hinder the construction of future generating facilities in North Dakota. The Company has filed a Motion to Intervene in the lawsuit and has joined in a brief supporting a Motion to Dismiss filed by the EPA. The Company cannot predict the outcome of the Department or Dakota Resource Council matters or their ultimate impact on its operations. The Company is also involved in other legal actions in the ordinary course of its business. Although the outcomes of any such legal actions cannot be predicted, management believes that the outcomes with respect to these other legal proceedings will not have a material adverse effect upon the Company's financial position or results of operations. Environmental matters In December 2000, Morse Bros., Inc. (MBI), an indirect wholly owned subsidiary of the Company, was named by the EPA as a Potentially Responsible Party in connection with the cleanup of a commercial property site, acquired by MBI in 1999, and part of the Portland, Oregon, Harbor Superfund Site. Sixty-eight other parties were also named in this administrative action. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. To date, costs of the overall remedial investigation of the harbor site for both the EPA and the Oregon State Department of Environmental Quality (DEQ) are being recorded, and initially paid, through an administrative consent order by the Lower Willamette Group (LWG), a group of 10 entities that does not include MBI. The LWG estimates the overall remedial investigation and feasibility study will cost approximately $10 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and feasibility study has been completed, the EPA has decided on a strategy, and a record of decision has been published. While the remedial investigation and feasibility study for the harbor site has commenced, it is expected to take several years to complete. The development of a proposed plan and record of decision on the harbor site is not anticipated to occur until 2006, after which a cleanup plan will be undertaken. Based upon a review of the Portland Harbor sediment contamination evaluation by the DEQ and other information available, MBI does not believe it is a Responsible Party. In addition, MBI has notified Georgia-Pacific West, Inc., the seller of the commercial property site to MBI, that it intends to seek indemnity for any and all liabilities incurred in relation to the above matters, pursuant to the terms of their sale agreement. The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above administrative action. Operating leases The Company leases certain equipment, facilities and land under operating lease agreements. The amounts of annual minimum lease payments due under these leases as of December 31, 2003, were $18.1 million in 2004, $12.4 million in 2005, $8.7 million in 2006, $5.1 million in 2007, $3.9 million in 2008 and $22.1 million thereafter. Rent expense was approximately $27.2 million, $26.9 million and $31.5 million for the years ended December 31, 2003, 2002 and 2001, respectively. Purchase commitments The Company has entered into various commitments, largely natural gas and coal supply, purchased power, natural gas transportation, construction materials supply and electric generation construction contracts. These commitments range from one to 21 years. The commitments under these contracts as of December 31, 2003, were $167.2 million in 2004, $67.2 million in 2005, $50.1 million in 2006, $31.0 million in 2007, $30.9 million in 2008 and $146.3 million thereafter. Amounts purchased under these various commitments for the years ended December 31, 2003, 2002 and 2001, were approximately $204.6 million, $152.1 million and $193.0 million, respectively. These commitments are not reflected in the Company's consolidated financial statements. Guarantees Centennial has unconditionally guaranteed a portion of certain bank borrowings of MPX in connection with the Company's equity method investment in the natural gas-fired electric generating facility in Brazil, as discussed in Note 2. The Company, through MDU Brasil, owns 49 percent of MPX. The main business purpose of Centennial extending the guarantee to MPX's creditors is to enable MPX to obtain lower borrowing costs. At December 31, 2003, the aggregate amount of borrowings outstanding subject to these guarantees was $45.5 million and the scheduled repayment of these borrowings is $11.0 million in 2004, $10.7 million in 2005, $10.7 million in 2006, $10.7 million in 2007 and $2.4 million in 2008. The individual investor (who through EBX Empreendimentos Ltda. (EBX), a Brazilian company, owns 51 percent of MPX) has also guaranteed a portion of these loans. In the event MPX defaults under its obligation, Centennial and the individual investor would be required to make payments under their guarantees. Centennial and the individual investor have entered into reimbursement agreements under which they have agreed to reimburse each other to the extent they may be required to make any guarantee payments in excess of their proportionate ownership share in MPX. These guarantees are not reflected on the Consolidated Balance Sheets. In addition, WBI Holdings, Inc. (WBI Holdings), an indirect wholly owned subsidiary of the Company, has guaranteed certain of its subsidiary's natural gas and oil price swap and collar agreement obligations. The amount of the subsidiary's obligations at December 31, 2003, was $1.8 million. There is no fixed maximum amount guaranteed in relation to the natural gas and oil price swap and collar agreements, as the amount of the obligation is dependent upon natural gas and oil commodity prices. The amount of hedging activity entered into by the subsidiary is limited by corporate policy. The guarantees of the natural gas and oil price swap and collar agreements at December 31, 2003, expire in 2004; however, the subsidiary continues to enter into additional hedging activities and, as a result, WBI Holdings from time to time may issue additional guarantees on these hedging obligations. At December 31, 2003, the amount outstanding was reflected on the Consolidated Balance Sheets. In the event the above subsidiary defaults under its obligations, WBI Holdings would be required to make payments under its guarantees. Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company that are related to natural gas transportation and sales agreements, electric power supply agreements, insurance policies and certain other guarantees. At December 31, 2003, the fixed maximum amounts guaranteed under these agreements aggregated $46.4 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $20.1 million in 2004; $5.9 million in 2005; $3.5 million in 2006; $500,000 in 2007; $900,000 in 2009; $12.0 million in 2012; $500,000, which is subject to expiration 30 days after the receipt of written notice and $3.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $372,000 and was reflected on the Consolidated Balance Sheets at December 31, 2003. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee. Fidelity and WBI Holdings have outstanding guarantees to Williston Basin. These guarantees are related to natural gas transportation and storage agreements that guarantee the performance of Prairielands Energy Marketing, Inc. (Prairielands), an indirect wholly owned subsidiary of the Company. At December 31, 2003, the fixed maximum amounts guaranteed under these agreements aggregated $22.9 million. Scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $2.9 million in 2005 and $20.0 million in 2009. In the event of Prairielands' default in its payment obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee. The amount outstanding by Prairielands under the above guarantees was $837,000, which was not reflected on the Consolidated Balance Sheet at December 31, 2003, because these intercompany transactions are eliminated in consolidation. In addition, Centennial has issued guarantees related to the Company's purchase of maintenance items to third parties for which no fixed maximum amounts have been specified. These guarantees have no scheduled maturity date. In the event a subsidiary of the Company defaults under its obligation in relation to the purchase of certain maintenance items, Centennial would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these maintenance items were reflected on the Consolidated Balance Sheet at December 31, 2003. As of December 31, 2003, Centennial was contingently liable for the performance of certain of its subsidiaries under approximately $360 million of surety bonds. These bonds are principally for construction contracts and reclamation obligations of these subsidiaries entered into in the normal course of business. Centennial indemnifies the respective surety bond companies against any exposure under the bonds. The purpose of Centennial's indemnification is to allow the subsidiaries to obtain bonding at competitive rates. In the event a subsidiary of the Company does not fulfill its obligations in relation to its bonded contract or obligation, Centennial may be required to make payments under its indemnification. A large portion of these contingent commitments are expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. The surety bonds were not reflected on the Consolidated Balance Sheets. Independent Auditors' Report To the Board of Directors and Stockholders of MDU Resources Group, Inc.: We have audited the accompanying consolidated balance sheets of MDU Resources Group, Inc. (the "Company") as of December 31, 2003 and 2002, and the related consolidated statements of income, common stockholders' equity, and cash flows for the years then ended. Our audits also included the 2003 and 2002 financial statement schedules listed in the Index at Item 15. These consolidated financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. The consolidated financial statements and financial statement schedule of the Company for the year ended December 31, 2001, before the adjustments described in Note 11, additional transitional disclosures described in Notes 3 and 9, and the reclassifications to the consolidated financial statements described in Note 1, were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those consolidated financial statements and stated that such 2001 financial statement schedule, when considered in relation to the 2001 basic consolidated financial statements taken as a whole, presented fairly, in all material respects, the information set forth therein, in their reports dated January 23, 2002. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the 2003 and 2002 consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the 2003 and 2002 financial statement schedules, when considered in relation to the 2003 and 2002 consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. As discussed above, the consolidated financial statements of the Company for the year ended December 31, 2001 were audited by other auditors who have ceased operations. As described in Note 11, those consolidated financial statements have been revised to give effect to the stock split on October 29, 2003. We audited the adjustments described in Note 11 that were applied to revise the 2001 consolidated financial statements for such stock split. Our audit procedures included (1) comparing the amounts shown in the earnings per share disclosures for 2001 to the Company's underlying accounting analysis obtained from management, (2) comparing the previously reported shares outstanding and income statement amounts per the Company's accounting analysis to the previously issued consolidated financial statements, and (3) recalculating the additional shares to give effect to the stock split and testing the mathematical accuracy of the underlying analysis. Also, as described in Note 3, these consolidated financial statements have been revised to include the transitional disclosures required by Statement of Financial Accounting Standards ("SFAS") No. 142, Goodwill and Other Intangible Assets, which was adopted by the Company as of January 1, 2002. Our audit procedures, with respect to the disclosures in Note 3 with respect to the 2001 disclosures, included (a) comparing the previously reported net income to the previously issued consolidated financial statements and the adjustments to reported net income representing amortization expense (including any related tax effects) recognized in those periods related to goodwill that is no longer being amortized as a result of initially applying SFAS No. 142 (including any tax effects) to the Company's underlying analysis obtained from management, and (b) testing the mathematical accuracy of (i) the reconciliation of adjusted net income to reported net income and (ii) the related earnings per share amounts. Also, as described in Note 1, these consolidated financial statements have been reclassified to include additional disclosures relating to the components comprising operating revenues and operation and maintenance expenses. Our audit procedures with respect to 2001 as it relates to the reclassifications described in Note 1 included (1) comparing the previously reported operating revenues and operation and maintenance expenses to previously issued consolidated financial statements, (2) comparing the operating revenues and operation and maintenance expenses to the Company's underlying analysis obtained from management, and (3) testing the mathematical accuracy of the underlying analysis. Also, as described in Note 9, these consolidated financial statements have been revised to include disclosures required by SFAS No. 143, Accounting for Asset Retirement Obligations, which was adopted by the Company as of January 1, 2003. Our audit procedures with respect to the disclosures in Note 9 as they relate to 2001 included testing the mathematical accuracy of the underlying analysis. In our opinion, the 2001 adjustments for the stock split described in Note 11 have been properly applied, the goodwill disclosures for 2001 in Note 3 and the asset retirement disclosures for 2001 in Note 9 are appropriate, and the reclassifications to the consolidated financial statements described in Note 1 have been properly applied. However, we were not engaged to audit, review, or apply any procedures to the 2001 consolidated financial statements of the Company other than with respect to such adjustments, reclassifications, and disclosures and, accordingly, we do not express an opinion or any other form of assurance on the 2001 consolidated financial statements taken as a whole. As discussed in Notes 1 and 9 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations; and as discussed in Notes 1 and 3 to the consolidated financial statements, effective January 1, 2002, the Company changed its method of accounting for goodwill. /s/ DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Minneapolis, Minnesota February 17, 2004 THIS IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN LLP. THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP NOR HAS ARTHUR ANDERSEN LLP PROVIDED A CONSENT TO THE INCLUSION OF ITS REPORT IN THIS ANNUAL REPORT. Report of Independent Public Accountants To MDU Resources Group, Inc.: We have audited the accompanying consolidated balance sheets of MDU Resources Group, Inc. (a Delaware corporation) and Subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, common stockholders' equity and cash flows for each of the three years in the period ended December 31, 2001. 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 auditing standards generally accepted in the United States. 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, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 1 to the consolidated financial statements, effective January 1, 2001, the company changed its method of accounting for derivative instruments due to the adoption of a new accounting pronouncement. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Minneapolis, Minnesota January 23, 2002 THIS IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN LLP. THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP NOR HAS ARTHUR ANDERSEN LLP PROVIDED A CONSENT TO THE INCLUSION OF ITS REPORT IN THIS ANNUAL REPORT. To MDU Resources Group, Inc.: We have audited in accordance with auditing standards generally accepted in the United States, the financial statements included in MDU Resources Group, Inc.'s annual report to stockholders incorporated by reference in this Form 10-K, and have issued our report thereon dated January 23, 2002. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. Schedule II is the responsibility of the company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states 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 LLP ARTHUR ANDERSEN LLP Minneapolis, Minnesota, January 23, 2002 Quarterly Data (Unaudited) The following unaudited information shows selected items by quarter for the years 2003 and 2002: First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per share amounts) 2003 Operating revenues $467,753 $548,219 $716,099 $620,118 Operating expenses 414,806 473,534 600,433 551,344 Operating income 52,947 74,685 115,666 68,774 Income before cumulative effect of accounting change 27,697 43,473 65,521 46,222 Cumulative effect of accounting change (7,589) --- --- --- Net income 20,108 43,473 65,521 46,222 Earnings per common share -- basic: Earnings before cumulative effect of accounting change .25 .39 .58 .41 Cumulative effect of accounting change (.07) --- --- --- Earnings per common share -- basic .18 .39 .58 .41 Earnings per common share -- diluted: Earnings before cumulative effect of accounting change .25 .39 .58 .40 Cumulative effect of accounting change (.07) --- --- --- Earnings per common share -- diluted .18 .39 .58 .40 Weighted average common shares outstanding: Basic 110,318 110,602 112,359 112,618 Diluted 111,094 111,532 113,368 113,804 First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per share amounts) 2002 Operating revenues $381,935 $480,218 $612,398 $556,986 Operating expenses 336,138 429,023 522,227 478,032 Operating income 45,797 51,195 90,171 78,954 Net income 23,722 24,853 53,931 45,938 Earnings per common share: Basic .23 .23 .51 .42 Diluted .22 .23 .50 .42 Weighted average common shares outstanding: Basic 104,203 105,684 106,385 108,142 Diluted 105,020 106,540 107,017 108,864 Pro forma amounts assuming retroactive application of accounting change: Net income $ 23,126 $ 24,255 $ 53,332 $ 45,339 Earnings per common share -- basic .22 .23 .50 .42 Earnings per common share -- diluted .22 .23 .50 .41 Certain Company operations are highly seasonal and revenues from and certain expenses for such operations may fluctuate significantly among quarterly periods. Accordingly, quarterly financial information may not be indicative of results for a full year. Natural Gas and Oil Activities (Unaudited) Fidelity is involved in the acquisition, exploration, development and production of natural gas and oil resources. Fidelity's activities include the acquisition of producing properties with potential development opportunities, exploratory drilling and the operation and development of natural gas production properties. Fidelity shares revenues and expenses from the development of specified properties located primarily in the Rocky Mountain region of the United States and in and around the Gulf of Mexico in proportion to its ownership interests. Fidelity owns in fee or holds natural gas leases for the properties it operates in Colorado, Montana, North Dakota and Wyoming. These rights are in the Bonny Field located in eastern Colorado, the Cedar Creek Anticline in southeastern Montana and southwestern North Dakota, the Bowdoin area located in north-central Montana and in the Powder River Basin of Montana and Wyoming. The information that follows includes Fidelity's proportionate share of all its natural gas and oil interests. The following table sets forth capitalized costs and accumulated depreciation, depletion and amortization related to natural gas and oil producing activities at December 31: 2003 2002 2001 (In thousands) Subject to amortization $758,500 $603,151 $506,155 Not subject to amortization 104,339 145,692 122,354 Total capitalized costs 862,839 748,843 628,509 Less accumulated depreciation, depletion and amortization 305,349 239,964 195,469 Net capitalized costs $557,490 $508,879 $433,040 Capital expenditures, including those not subject to amortization, related to natural gas and oil producing activities were as follows: Years ended December 31, 2003* 2002 2001 (In thousands) Acquisitions $ 3,027 $ 31,439 $ 1,695 Exploration 19,193 5,325 13,938 Development** 77,583 94,943 102,670 Total capital expenditures $99,803 $131,707 $118,303 * Excludes $14,724 of additions to property, plant and equipment related to the recognition of future liabilities associated with the plugging and abandonment of natural gas and oil wells in accordance with SFAS No. 143, as discussed in Note 9. **Includes expenditures for proved undeveloped reserves of $23.3 million, $10.1 million and $15.0 million for the years ended December 31, 2003, 2002 and 2001, respectively. The following summary reflects income resulting from the Company's operations of natural gas and oil producing activities, excluding corporate overhead and financing costs: Years ended December 31, 2003 2002* 2001 (In thousands) Revenues: Sales to external customers $140,034 $145,170 $139,939 Sales to affiliates 124,077 55,437 61,178 Production costs 67,292 52,520 44,435 Depreciation, depletion and amortization 60,072** 48,064 41,223 Pretax income 136,747 100,023 115,459 Income tax expense 51,925 36,886 45,245 Results of operations for producing activities before cumulative effect of accounting change 84,822 63,137 70,214 Cumulative effect of accounting change (7,740) --- --- Results of operations for producing activities $ 77,082 $ 63,137 $ 70,214 * Includes the compromise agreement as discussed in Note 19. **Includes $1,356 of accretion of discount for asset retirement obligations in 2003 in accordance with SFAS No. 143, as discussed in Note 1. The following table summarizes the Company's estimated quantities of proved natural gas and oil reserves at December 31, 2003, 2002 and 2001, and reconciles the changes between these dates. Estimates of economically recoverable natural gas and oil 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. 2003 2002 2001 Natural Natural Natural Gas Oil Gas Oil Gas Oil (In thousands of Mcf/barrels) Proved developed and undeveloped reserves: Balance at beginning of year 372,500 17,500 324,100 17,500 309,800 15,100 Production (54,700) (1,900) (48,200) (2,000) (40,600) (2,000) Extensions and discoveries 113,300 3,300 80,100 2,200 66,400 2,000 Purchases of proved reserves 900 --- 1,200 100 1,000 100 Sales of reserves in place --- (100) (4,400) (300) --- --- Revisions of previous estimates (20,300) 100 19,700 --- (12,500) 2,300 Balance at end of year 411,700 18,900 372,500 17,500 324,100 17,500 Proved developed reserves: January 1, 2001 263,400 14,200 December 31, 2001 291,300 17,100 December 31, 2002 331,300 14,800 December 31, 2003 342,800 15,000 All of the Company's interests in natural gas and oil reserves are located in the United States and in and around the Gulf of Mexico. The standardized measure of the Company's estimated discounted future net cash flows of total proved reserves associated with its various natural gas and oil interests at December 31 was as follows: 2003 2002 2001 (In thousands) Future cash inflows $2,547,400 $1,726,000 $ 974,200 Future production costs 651,300 513,200 361,600 Future development costs 67,100 61,200 64,600 Future net cash flows before income taxes 1,829,000 1,151,600 548,000 Future income tax expense 601,000 324,000 112,000 Future net cash flows 1,228,000 827,600 436,000 10% annual discount for estimated timing of cash flows 491,200 321,300 174,000 Discounted future net cash flows relating to proved natural gas and oil reserves $ 736,800 $ 506,300 $ 262,000 The following are the sources of change in the standardized measure of discounted future net cash flows by year: 2003 2002 2001 (In thousands) Beginning of year $506,300 $262,000 $ 921,300 Net revenues from production (220,000) (112,900) (153,500) Change in net realization 318,600 296,100 (1,119,700) Extensions, discoveries and improved recovery, net of future production-related costs 245,800 117,000 40,200 Purchases of proved reserves 2,800 3,700 2,600 Sales of reserves in place (600) (8,900) --- Changes in estimated future development costs (4,000) (1,100) (6,700) Development costs incurred during the current year 35,300 19,400 31,600 Accretion of discount 62,400 27,300 122,700 Net change in income taxes (172,000) (124,700) 436,500 Revisions of previous estimates (35,500) 30,000 (11,700) Other (2,300) (1,600) (1,300) Net change 230,500 244,300 (659,300) End of year $736,800 $506,300 $ 262,000 The estimated discounted future cash inflows from estimated future production of proved reserves were computed using year-end natural gas prices and oil 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 development costs estimated to be spent in each of the next three years to develop proved undeveloped reserves are $37.1 million in 2004, $6.7 million in 2005 and $4.4 million in 2006. 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. The standardized measure of discounted future net cash flows does not purport to represent the fair market value of natural gas and oil properties. There are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production and the timing and amount of future costs. In addition, future realization of natural gas and oil prices over the remaining reserve lives may vary significantly from current prices. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES The following information includes the evaluation of disclosure controls and procedures by the Company's chief executive officer and the chief financial officer, along with any significant changes in internal controls of the Company. Evaluation of disclosure controls and procedures The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act). These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods. The Company's chief executive officer and chief financial officer have evaluated the effectiveness of the Company's disclosure controls and procedures and they have concluded that, as of the end of the period covered by this report, such controls and procedures were effective to accomplish those tasks. Changes in internal controls The Company maintains a system of internal accounting controls that is designed to provide reasonable assurance that the Company's transactions are properly authorized, the Company's assets are safeguarded against unauthorized or improper use, and the Company's transactions are properly recorded and reported to permit preparation of the Company's financial statements in conformity with generally accepted accounting principles in the United States of America. There were no changes in the Company's internal control over financial reporting that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item is included under the captions "Election of Directors," "Continuing Incumbent Directors," "Information Concerning Executive Officers," "Board and Board Committees" and "Nominating and Governance Committee" in the Company's Proxy Statement dated March 5, 2004 (Proxy Statement), which is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The information required by this item is included under the captions "Directors' Compensation" and "Executive Compensation" of the Proxy Statement, which is incorporated herein by reference with the exception of the compensation committee report on executive compensation and the performance graph. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information required by this item is included under the captions "Security Ownership" and "Proposal to Amend the Non- Employee Director Stock Compensation Plan" of the Proxy Statement, which is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The information required by this item is included under the caption "Accounting and Auditing Matters" of the Proxy Statement, which is incorporated herein by reference. PART IV ITEM 15. 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: The following consolidated financial statements required under this item are included under Item 8 -- Financial Statements and Supplementary Data. Consolidated Statements of Income for each of the three years in the period ended December 31, 2003 Consolidated Balance Sheets at December 31, 2003 and 2002 Consolidated Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 2003 Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2003 Notes to Consolidated Financial Statements 2. Financial Statement Schedules: MDU RESOURCES GROUP, INC. SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 Additions _______________________ Balance at Charged to beginning costs and Balance at Description of year expenses Other(a)(b) Deductions(c) end of year (In thousands) Allowance for doubtful accounts: 2003 $8,237 $3,185 $1,123 $4,399 $8,146 2002 5,773 8,192 1,164 6,892 8,237 2001 4,063 3,896 2,003 4,189 5,773 (a) Allowance for doubtful accounts for companies acquired (b) Recoveries (c) Uncollectible accounts written off All other schedules are omitted because of the absence of the conditions under which they are required, or because the information required is included in the Company's Consolidated Financial Statements and Notes thereto. 3. Exhibits: 3(a) Restated Certificate of Incorporation of the Company, as amended, filed as Exhibit 3(a) to Form S-3 on June 13, 2003, in Registration No. 333-104150 * 3(b) By-laws of the Company, as amended, filed as Exhibit 3.3 to Form 8-A/A on March 10, 2003, in File No. 1-3480 * 3(c) Certificate of Designations of Series B Preference Stock of the Company, as amended, filed as Exhibit 3(a) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * 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-Ninth Supplements thereto between the Company and the New York Trust Company (The Bank of New York, successor Corporate Trustee) and A. C. Downing (Douglas J. MacInnes, 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; and Exhibit 4(c)(i) in Registration No. 333-49472 * 4(b) Fiftieth Supplemental Indenture, dated as of December 15, 2003, filed as Exhibit 4(e) to Form S-8 on January 21, 2004, in Registration No. 333-112035 * 4(c) Rights agreement, dated as of November 12, 1998, between the Company and Wells Fargo Bank Minnesota, N.A. (formerly known as Norwest Bank Minnesota, N.A.), Rights Agent, filed as Exhibit 4.1 to Form 8-A on November 12, 1998, in File No. 1-3480 * 4(d) Indenture, dated as of December 15, 2003, between the Company and The Bank of New York, as trustee, filed as Exhibit 4(f) to Form S-8 on January 21, 2004, in Registration No. 333-112035 * 4(e) Certificate of Adjustment to Purchase Price and Redemption Price, as amended and restated, pursuant to the Rights Agreement, dated as of November 12, 1998 ** + 10(a) Executive Incentive Compensation Plan, as amended ** + 10(b) 1992 Key Employee Stock Option Plan, as amended, filed as Exhibit 10(b) to Form 10-K for the year ended December 31, 2002, in File No. 1-3480 * + 10(c) Supplemental Income Security Plan, as amended, filed as Exhibit 10(c) to Form 10-K for the year ended December 31, 2002, in File No. 1-3480 * + 10(d) Directors' Compensation Policy, as amended, filed as Exhibit 10(a) to Form 10-Q for the quarter ended June 30, 2003, in File No. 1-3480 * + 10(e) Deferred Compensation Plan for Directors, as amended, filed as Exhibit 10(e) to Form 10-K for the year ended December 31, 2002, in File No. 1-3480 * + 10(f) Non-Employee Director Stock Compensation Plan, as amended, filed as Exhibit 10(b) to Form 10-Q for the quarter ended June 30, 2003, in File No. 1-3480 * + 10(g) 1997 Non-Employee Director Long-Term Incentive Plan, as amended, filed as Exhibit 10(d) to Form 10-Q for the quarter ended June 30, 2000, in File No. 1-3480 * + 10(h) 1997 Executive Long-Term Incentive Plan, as amended, filed as Exhibit 10(a) to Form 10-Q for the quarter ended March 31, 2001, in File No. 1-3480 * + 10(i) Change of Control Employment Agreement between the Company and John K. Castleberry, filed as Exhibit 10(a) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(j) Change of Control Employment Agreement between the Company and Cathleen M. Christopherson, filed as Exhibit 10(b) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(k) Change of Control Employment Agreement between the Company and Richard A. Espeland, filed as Exhibit 10(c) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(l) Change of Control Employment Agreement between the Company and Terry D. Hildestad, filed as Exhibit 10(d) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(m) Change of Control Employment Agreement between the Company and Vernon A. Raile, filed as Exhibit 10(f) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(n) Change of Control Employment Agreement between the Company and Warren L. Robinson, filed as Exhibit 10(g) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(o) Change of Control Employment Agreement between the Company and William E. Schneider, filed as Exhibit 10(h) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(p) Change of Control Employment Agreement between the Company and Ronald D. Tipton, filed as Exhibit 10(i) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(q) Change of Control Employment Agreement between the Company and Martin A. White, filed as Exhibit 10(j) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(r) Change of Control Employment Agreement between the Company and Robert E. Wood, filed as Exhibit 10(k) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(s) Separation Agreement and Release between the Company and Douglas C. Kane, filed as Exhibit 10(t) to Form 10-K for the year ended December 31, 2002, in File No. 1-3480 * + 10(t) 1998 Option Award Program, filed as Exhibit 10(u) to Form 10-K for the year ended December 31, 2002, in File No. 1-3480 * + 10(u) Group Genius Innovation Plan, filed as Exhibit 10(v) to Form 10-K for the year ended December 31, 2002, in File No. 1-3480 * + 10(v) Agreement on Retirement between the Company and Lester H. Loble, II ** + 10(w) The Wagner-Smith Company Deferred Compensation Plan ** + 10(x) Wagner-Smith Equipment Co. Deferred Compensation Plan ** + 10(y) The Capital Electric Construction Company, Inc. Deferred Compensation Plan ** + 10(z) The Capital Electric Line Builders, Inc. Deferred Compensation Plan ** + 10(aa) The Bauerly Brothers, Inc. Deferred Compensation Plan ** + 10(ab) The Oregon Electric Construction, Inc. Deferred Compensation Plan ** 12 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends ** 21 Subsidiaries of MDU Resources Group, Inc. ** 23(a) Independent Auditors' Consent ** 23(b) Notice regarding consent of Arthur Andersen LLP ** 31(a) Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 ** 31(b) Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 ** 32 Certification of Chief Executive Officer and Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** * 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 15(c) of this report. (b) Reports on Form 8-K Form 8-K was filed on October 24, 2003. Under Item 12 -- Results of Operations and Financial Condition, the Company reported the press release issued October 24, 2003, regarding earnings for the quarter ended September 30, 2003. Form 8-K was filed on November 18, 2003. Under Item 5 -- Other Events, the Company reported an alliance formed with Basin Electric Power Cooperative to evaluate potential utility opportunities presented by NorthWestern Corporation's bankruptcy filing. Form 8-K was filed on December 17, 2003. Under Item 5 -- Other Events and Required FD Disclosure, the Company filed an Underwriting Agreement relating to a public offering of Senior Notes. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. MDU RESOURCES GROUP, INC. Date: February 27, 2004 By: /s/ Martin A. White Martin A. White (Chairman of the Board, President and Chief Executive Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the date indicated. Signature Title Date /s/ Martin A. White Chief Executive February 27, 2004 Martin A. White (Chairman of the Board, Officer President and Chief Executive Officer) and Director /s/ Warren L. Robinson Chief Financial February 27, 2004 Warren L. Robinson (Executive Vice Officer President and Chief Financial Officer) /s/ Vernon A. Raile Chief Accounting February 27, 2004 Vernon A. Raile (Senior Vice President Officer and Chief Accounting Officer) /s/ Harry J. Pearce Lead Director February 27, 2004 Harry J. Pearce Director Bruce R. Albertson /s/ Thomas Everist Director February 27, 2004 Thomas Everist /s/ Dennis W. Johnson Director February 27, 2004 Dennis W. Johnson /s/ Patricia L. Moss Director February 27, 2004 Patricia L. Moss /s/ Robert L. Nance Director February 27, 2004 Robert L. Nance /s/ John L. Olson Director February 27, 2004 John L. Olson /s/ Homer A. Scott, Jr. Director February 27, 2004 Homer A. Scott, Jr. /s/ Sister Thomas Welder Director February 27, 2004 Sister Thomas Welder /s/ John K. Wilson Director February 27, 2004 John K. Wilson

Dates Referenced Herein   and   Documents Incorporated by Reference

This ‘10-K’ Filing    Date    Other Filings
6/1/22
12/31/20
12/31/1010-K,  11-K,  4,  8-K
1/1/09
12/31/0810-K,  11-K,  4,  8-K
1/1/08
12/31/0710-K,  11-K,  4
4/30/074
1/1/07
12/31/0610-K,  10-K/A,  11-K
11/1/06
10/31/06
9/5/06
7/18/06
5/1/064,  8-K
11/30/054,  8-K
10/31/05
5/1/053
3/31/0510-Q,  4,  8-K
12/31/0410-K,  11-K,  4,  5,  8-K
10/31/04
10/30/04
10/15/04
10/1/044
9/3/044/A
7/15/04
5/1/04
3/15/044/A
3/5/04
2/29/04
Filed on:2/27/044
2/20/044
2/17/044,  4/A
2/10/04
2/6/044
1/31/04
1/23/04
1/21/048-A12B/A,  S-8
1/16/04
1/14/04
1/9/043
1/7/04
For Period End:12/31/0311-K,  4,  4/A,  5,  8-K
12/23/03
12/18/03424B5
12/17/038-K
12/15/03
12/2/03
11/19/033/A
11/18/038-K
11/10/03
10/31/03
10/29/03
10/27/03
10/24/038-K
10/22/03
10/10/03
10/9/03
10/8/03
10/1/03
9/30/0310-Q,  4,  8-K
9/14/03
9/3/03
8/14/03
8/4/03
7/23/03
7/3/03
6/30/0310-Q,  4,  8-K
6/15/03
6/13/03S-3/A
5/31/03
5/30/03
3/10/038-A12B/A,  POS AM
2/3/03
1/31/03
1/1/03
12/31/0210-K,  11-K,  8-K
12/15/02
12/6/02
11/1/028-K
10/31/02
9/30/0210-Q
8/12/02
7/10/02
7/1/02
6/15/02
5/15/02
4/23/02DEF 14A,  PRE 14A
1/23/02
1/1/02
12/31/0110-K,  11-K,  424B2,  8-K
6/30/0110-Q,  8-K
4/30/01
3/31/0110-Q
1/1/01
12/31/0010-K,  11-K,  8-K
6/30/0010-Q
6/1/00
4/1/00
12/31/9910-K,  11-K
11/12/9810-Q,  8-A12B,  8-K
5/2/97
4/21/92
 List all Filings 
Top
Filing Submission 0000067716-04-000045   –   Alternative Formats (Word / Rich Text, HTML, Plain Text, et al.)

Copyright © 2024 Fran Finnegan & Company LLC – All Rights Reserved.
AboutPrivacyRedactionsHelp — Fri., Mar. 29, 4:22:18.2am ET