SEC Info - Mdu Resources Group Inc - ‘10-K’ for 12/31/05

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, 2005

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 incorporation or organization)		(I.R.S. Employer Identification No.)

1200 West Century Avenue

P.O. Box 5650

Bismarck, North Dakota 58506-5650

(Address of principal executive offices)

(Zip Code)

(701) 530-1000

(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 on which registered
Common Stock, par value $1.00 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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No x.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o.

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer x Accelerated filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x.

State the aggregate market value of the voting stock held by nonaffiliates of the registrant as of June 30, 2005: $3,371,397,000.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of February 15, 2006: 119,954,082 shares.

DOCUMENTS INCORPORATED BY REFERENCE.

Portions of the registrant’s 2006 Proxy Statement 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
Construction Services
Pipeline and Energy Services
Natural Gas and Oil Production
Construction Materials and Mining
Independent Power Production

Item 1A Risk Factors

Item 1B Unresolved Comments

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 Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities

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 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Item 9A Controls and Procedures

Item 9B Other Information

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 and Financial Statement Schedules

Signatures

Exhibits

DEFINITIONS

The following abbreviations and acronyms used in this Form 10-K are defined below:

Abbreviation or Acronym

2003 Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
AFUDC	Allowance for funds used during construction
ALJ	Administrative Law Judge
Anadarko	Anadarko Petroleum Corporation
APB	Accounting Principles Board
APB Opinion No. 25	Accounting for Stock-Based Compensation
Arch	Arch Coal Sales Company
Army Corps	U.S. Army Corps of Engineers
Badger Hills Project	Tongue River-Badger Hills Project
Bbl	Barrel
Bcf	Billion cubic feet
BER	Montana Board of Environmental Review
Bitter Creek	Bitter Creek Pipelines, LLC, an indirect wholly owned subsidiary of WBI Holdings
BIV	BIV Generation Company, L.L.C., an indirect wholly owned subsidiary of Centennial Power
Black Hills Power	Black Hills Power and Light Company
BLM	Bureau of Land Management
Brush Generating Facility	213 MW of natural gas-fired electric generating facilities located near Brush, Colorado
Btu	British thermal units
Carib Power	Carib Power Management LLC
CDPHE	Colorado Department of Public Health and Environment
CEM	Colorado Energy Management, LLC, a direct wholly owned subsidiary of Centennial Resources
Centennial	Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
Centennial Capital	Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Centennial International	Centennial Energy Resources International, Inc., a direct wholly owned subsidiary of Centennial Resources
Centennial Power	Centennial Power, Inc., a direct wholly owned subsidiary of Centennial Resources
Centennial Resources	Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act
Clean Air Act	Federal Clean Air Act
Clean Water Act	Federal Clean Water Act
Company	MDU Resources Group, Inc.
CPP	Colorado Power Partners, an indirect wholly owned subsidiary of Centennial Power
D.C. Appeals Court	U.S. Court of Appeals for the District of Columbia Circuit
DEQ	Oregon State Department of Environmental Quality
dk	Decatherm
EITF	Emerging Issues Task Force
EITF No. 04-6	Accounting for Stripping Costs in the Mining Industry
EITF No. 91-6	Revenue Recognition of Long-Term Power Sales Contracts
EPA	U.S. Environmental Protection Agency
ESA	Endangered Species Act
Exchange Act	Securities Exchange Act of 1934
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fidelity	Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings
FIN	FASB Interpretation No.
FIN 47	Accounting for Conditional Asset Retirement Obligations - An Interpretation of FASB Statement No. 143
Great Plains	Great Plains Natural Gas Co., a public utility division of the Company
Grynberg	Jack J. Grynberg
Hardin Generating Facility	116-MW coal-fired electric generating facility near Hardin, Montana
Hartwell	Hartwell Energy Limited Partnership
Hartwell Generating Facility	310-MW natural gas-fired electric generating facility near Hartwell, Georgia (50 percent ownership)
Howell	Howell Petroleum Corporation
IBEW	International Brotherhood of Electrical Workers
Innovatum	Innovatum, Inc., an indirect wholly owned subsidiary of WBI Holdings
K-Plan	Company’s 401(k) Retirement Plan
Kennecott	Kennecott Coal Sales Company
Knife River	Knife River Corporation, a direct wholly owned subsidiary of Centennial
kW	Kilowatts
kWh	Kilowatt-hour
LWG	Lower Willamette Group
MAPP	Mid-Continent Area Power Pool
MBbls	Thousands of barrels of oil or other liquid hydrocarbons
MBI	Morse Bros., Inc., an indirect wholly owned subsidiary of Knife River
Mcf	Thousand cubic feet
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Mdk	Thousand decatherms
MDU Brasil	MDU Brasil Ltda., an indirect wholly owned subsidiary of Centennial International
MDU Construction Services	MDU Construction Services Group, Inc., formerly Utility Services, Inc. (name change was effective December 23, 2005), a direct wholly owned subsidiary of Centennial
Midwest ISO	Midwest Independent Transmission System Operator, Inc.
MMBtu	Million Btu
MMcf	Million cubic feet
MMcfe	Million cubic feet equivalent
MMdk	Million decatherms
Montana-Dakota	Montana-Dakota Utilities Co., a public utility division of the Company
Montana Federal District Court	U.S. District Court for the District of Montana
MPUC	Minnesota Public Utilities Commission
MPX	MPX Termoceara Ltda.
MTPSC	Montana Public Service Commission
MW	Megawatt
Nance Petroleum	Nance Petroleum Corporation
ND Health Department	North Dakota Department of Health
NDPSC	North Dakota Public Service Commission
NEO	Named Executive Officers
NEPA	National Environmental Policy Act
NHPA	National Historic Preservation Act
Ninth Circuit	U.S. Ninth Circuit Court of Appeals
NPRC	Northern Plains Resource Council
Oglethorpe	Oglethorpe Power Corporation
Order on Rehearing	Order on Rehearing and Compliance and Remanding Certain Issues for Hearing
PCBs	Polychlorinated biphenyls
Prairielands	Prairielands Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI Holdings
Proxy Statement	Company’s 2006 Proxy Statement
PSCo	Public Service Company of Colorado
RCRA	Resource Conservation and Recovery Act
SAB	Staff Accounting Bulletin
SAB No. 106	Interpretation regarding the application of SFAS No. 143 by oil and gas producing companies following the full-cost accounting method
SAFETEA-LU	Safe, Accountable, Flexible and Efficient Transportation Equity Act - A Legacy for Users
SDPUC	South Dakota Public Utilities Commission
SEC	U.S. Securities and Exchange Commission
SEIS	Supplemental Environmental Impact Statement
SFAS	Statement of Financial Accounting Standards
SFAS No. 71	Accounting for the Effects of Certain Types of Regulation
SFAS No. 87	Employers’ Accounting for Pensions
SFAS No. 109	Accounting for Income Taxes
SFAS No. 123	Accounting for Stock-Based Compensation
SFAS No. 123 (revised)	Share-Based Payment (revised 2004)
SFAS No. 142	Goodwill and Other Intangible Assets
SFAS No. 143	Accounting for Asset Retirement Obligations
SFAS No. 148	Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123
Sheridan System	A separate electric system owned by Montana-Dakota
SMCRA	Surface Mining Control and Reclamation Act
St. Mary	St. Mary Land & Exploration Company
Stock Purchase Plan	Company’s Dividend Reinvestment and Direct Stock Purchase Plan
Termoceara Generating Facility	220-MW natural gas-fired electric generating facility in the Brazilian state of Ceara (49 percent ownership)
Trinity Generating Facility	225-MW natural gas-fired electric generating facility in Trinidad and Tobago (49.99 percent ownership)
T&TEC	Trinidad and Tobago Electric Commission
WAPA	Western Area Power Administration
WBI Holdings	WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
Westmoreland	Westmoreland Coal Company
Williston Basin	Williston Basin Interstate Pipeline Company, an indirect wholly owned subsidiary of WBI Holdings
Wyoming Federal District Court	U.S. District Court for the District of Wyoming
WYPSC	Wyoming Public Service Commission

PART I

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 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 530-1000.

Montana-Dakota, through the electric and natural gas distribution segments, generates, transmits and distributes electricity and distributes natural gas in Montana, North Dakota, South Dakota and Wyoming. Great Plains distributes natural gas in western Minnesota and southeastern North Dakota. These operations also supply related value-added products and services.

The Company, through its wholly owned subsidiary, Centennial, owns WBI Holdings, Knife River, MDU Construction Services, Centennial Resources and 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, development and production activities primarily in the Rocky Mountain and Mid-Continent regions 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 Alaska and Hawaii.

MDU Construction Services specializes in electrical line construction, pipeline construction, inside electrical wiring and cabling and the manufacture and distribution of specialty equipment.

Centennial Resources owns, builds and operates electric generating facilities in the United States and has investments in domestic and international natural resource-based projects. Electric capacity and energy produced at its power plants primarily are sold under mid- and long-term contracts to nonaffiliated entities.

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. These activities are reflected in the Other category.

As of December 31, 2005, the Company had 10,030 full-time employees with 120 employed at MDU Resources Group, Inc., 881 at Montana-Dakota, 52 at Great Plains, 514 at WBI Holdings, 4,438 at Knife River, 3,893 at MDU Construction Services and 132 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, 429 and 76 employees, respectively, are represented by the IBEW. Labor contracts with such employees are in effect through April 30, 2007, and March 31, 2008, for Montana-Dakota and Williston Basin, respectively.

Knife River has 43 labor contracts that represent approximately 800 of its construction materials employees. Knife River is currently in negotiations on seven of its labor contracts.

MDU Construction Services has 86 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 - MD&A and Item 8 - Financial Statements and Supplementary Data - Note 13 and Supplementary Financial Information.

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 to 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 - Construction Materials and Mining - Environmental Matters, Item 3 - Legal Proceedings and in Item 8 - Financial Statements and Supplementary Data - Note 18 and also the coalbed natural gas development, which is discussed under Item 3 - Legal Proceedings and in Item 8 - Financial Statements and Supplementary Data - Note 18. There are no pending 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 free of charge through the Company’s Web site as soon as reasonably practicable after the Company has electronically filed such reports with, or furnished such reports to, the SEC. The Company’s Web site address is www.mdu.com. The information available on the Company’s Web site is not part of this annual report on Form 10-K.

ELECTRIC

General Montana-Dakota provides electric service at retail, serving over 118,000 residential, commercial, industrial and municipal customers located in 177 communities and adjacent rural areas as of December 31, 2005. 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 4,400 miles of transmission and distribution lines, respectively. Montana-Dakota has obtained and holds, or is in the process of renewing, 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 - MD&A - Prospective Information - Electric. As of December 31, 2005, Montana-Dakota's net electric plant investment approximated $296.5 million.

Substantially all of Montana-Dakota's electric properties 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 percentage of Montana-Dakota's 2005 retail electric utility operating revenues by jurisdiction is as follows: North Dakota - 59 percent; Montana - 24 percent; South Dakota - 7 percent and Wyoming - 10 percent. Retail electric rates, service, accounting and certain security issuances are subject to regulation by the NDPSC, MTPSC, SDPUC and WYPSC. The interstate transmission and wholesale electric power operations of Montana-Dakota are also subject to regulation by the FERC under provisions of the Federal Power Act, as are interconnections with other utilities and power generators, the issuance of securities, accounting and other matters. Montana-Dakota markets wholesale power into the Midwest ISO market.

System Supply and System Demand Through an interconnected electric system, Montana-Dakota serves markets in portions of 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 electric generating stations, which have an aggregate turbine nameplate rating attributable to Montana-Dakota's interest of 436,055 kW and a total summer net capability of 476,870 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. Additionally, Montana-Dakota has contracted to purchase 66,400 kW of participation power annually from Basin Electric Power Cooperative for its interconnected system, through October 31, 2006. Montana-Dakota also has an agreement through December 31, 2020, with 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 2,815 kW.

In July 2004, Montana-Dakota entered into a firm capacity contract to purchase 25 MW of capacity and associated energy for the summer of 2006 from a neighboring utility. In September 2005, Montana-Dakota entered into a contract for seasonal capacity from a neighboring utility, starting at 85 MW in 2007, increasing to 105 MW in 2011, with an option for capacity in 2012. Energy will also be purchased as needed from the Midwest ISO market.

The following table sets forth details applicable to the Company's electric generating stations:

							2005 Net
							Generation
			Nameplate		Summer		(kilowatt-
			Rating		Capability		hours in
Generating Station	Type		(kW)		(kW)		thousands)

North Dakota:
Coyote*		Steam		103,647		106,750		765,044
Heskett		Steam		86,000		103,070		604,887
Williston		Combustion Turbine		7,800		9,600		(72	)	**
South Dakota:
Big Stone*		Steam		94,111		104,550		662,836
Montana:
Lewis & Clark		Steam		44,000		52,300		283,984
Glendive		Combustion Turbine		77,347		77,800		8,634
Miles City		Combustion Turbine		23,150		22,800		1,915
				436,055		476,870		2,327,228

* Reflects Montana-Dakota's ownership interest.

** Station use, to meet MAPP’s accreditation requirements, exceeded generation.

On December 9, 2005, Montana-Dakota signed a power purchase agreement with a wind developer to purchase the production from a 31.5-MW wind-powered electric generating facility to be constructed in South Dakota by the end of 2007. This agreement is dependent upon the developer obtaining transmission and financing arrangements. If built, this plant is projected to produce about 124,000 MW hours annually.

Virtually all of the current fuel requirements of the Coyote, Heskett and Lewis & Clark stations are met with coal supplied by subsidiaries of Westmoreland. Contracts with Westmoreland for the Coyote and Lewis & Clark stations expire in May 2016 and December 2007, respectively. The contract with Westmoreland for the Heskett Station expired in December 2005 and Montana-Dakota is currently in negotiations regarding a replacement for this contract. In July 2004, Montana-Dakota entered into separate three-year coal supply agreements with each of Kennecott and Arch to meet the majority of the Big Stone Station’s fuel requirements for the years 2005 to 2007 at contracted pricing. The Kennecott agreement provides for the purchase during 2006 and 2007 of 1.5 million and 1.3 million tons of coal, respectively. The Arch agreement provides for the purchase of 500,000 tons of coal in both 2006 and 2007.

The Coyote coal supply agreement provides for the purchase of coal necessary to supply 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 Lewis & Clark coal supply agreement provides for the purchase of coal necessary to supply 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, 2001, through December 31, 2005, the average cost of coal purchased, including freight at Montana-Dakota's electric generating stations (including the Big Stone and Coyote stations) was as follows:

Years Ended December 31,	2005		2004		2003		2002		2001
Average cost of coal per million Btu	$	1.14	$	1.08	$	1.04	$	.98	$	.92
Average cost of coal per ton	$	17.01	$	15.96	$	15.22	$	14.39	$	13.43

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 2011 will approximate 1.3 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 through the year 2012. Future capacity that is needed to replace contracts and meet system growth requirements is expected to be met by building or acquiring additional capacity or through power contracts. For additional information regarding potential power generation projects, see Item 7 - MD&A - Prospective Information - Electric.

Montana-Dakota has major interconnections with its neighboring utilities, and considers these interconnections adequate for coordinated planning, emergency assistance, exchange of capacity and energy and power supply reliability.

Through the 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 54,900 kW and occurred in July 2005.

The Sheridan System is supplied through an interconnection with the PacifiCorp transmission system, under an agreement with Black Hills Power, as part of a power supply contract through December 31, 2006, which allows for the purchase of up to 55,000 kW of capacity annually. In December 2004, Montana-Dakota entered into a power supply contract with Black Hills Power to purchase up to 74,000 kW of capacity annually during the period from January 1, 2007, to December 31, 2016. This contract also provides an option for Montana-Dakota to purchase 25-MW of an existing or future baseload coal-fired electric generating facility from Black Hills Corporation to serve the Sheridan load.

The Midwest ISO is a regional transmission organization responsible for operational control of the transmission systems of its members. The Midwest ISO provides security center operations, tariff administration and operates a day-ahead and real-time energy market. Montana-Dakota sells energy unneeded for retail load at wholesale into, and will also purchase any needed energy from, this market.

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.

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, which in 2005 accounted for 24 percent of retail electric revenues, such cost changes are includable 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 EPA may authorize a state to manage federal programs, such as the Clean Air Act and Clean Water Act, under approved state programs. This is the case in all the states where Montana-Dakota operates.

Montana-Dakota's electric generating facilities have Title V Operating Permits, under the Clean Air Act, issued by the states in which it operates. Each of these permits has a five-year life. Near the expiration of these permits, renewal applications are submitted. Permits continue in force beyond the expiration date, provided the application for renewal is submitted by the required date, usually six months prior to expiration. Three permits were renewed in 2005. The next permit will expire in 2009. One facility operates under a minor source permit, which expires in 2006. A timely application for renewal will be submitted. 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 five-year lives. Montana-Dakota renews these permits as necessary prior to expiration. One permit expired on November 30, 2005, and a timely renewal application was submitted, so the permit continues in force. 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 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 RCRA. Montana-Dakota routinely handles PCBs from its 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 2005. Expenditures are estimated to be $2.1 million, $2.6 million and $1.8 million in 2006, 2007 and 2008, respectively, to maintain environmental compliance as new emission controls are required. Projects will include nitrogen-oxide, sulfur-dioxide and mercury control equipment installation at the power plants. For matters involving Montana-Dakota and the ND Health Department, see Item 3 - Legal Proceedings.

NATURAL GAS DISTRIBUTION

General Montana-Dakota sells natural gas at retail, serving over 228,000 residential, commercial and industrial customers located in 144 communities and adjacent rural areas as of December 31, 2005, 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, 2005, 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 approximately 5,500 miles. Montana-Dakota and Great Plains have obtained and hold, or are in the process of renewing, valid and existing franchises authorizing them to conduct their natural gas 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 - MD&A - Prospective Information - Natural gas distribution. As of December 31, 2005, Montana-Dakota's and Great Plains' net natural gas distribution plant investment approximated $158.7 million.

Substantially all of Montana-Dakota's natural gas distribution properties 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 percentage of Montana-Dakota's and Great Plains' 2005 natural gas utility operating revenues by jurisdiction is as follows: North Dakota - 39 percent; Minnesota - 11 percent; Montana - 25 percent; South Dakota - 19 percent and Wyoming - 6 percent. 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 certain security issuances. The natural gas distribution operations of Great Plains are subject to regulation by the NDPSC and MPUC regarding retail rates, service, accounting and certain security issuances.

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 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 largely on the weather, the effects of which are mitigated in certain jurisdictions by a weather normalization mechanism discussed in Regulatory Matters.

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,	2005			2004			2003			2002			2001
	(Mdk)
Sales:
Residential		20,086			20,303			21,498			21,893			20,087
Commercial		14,457			14,598			15,537			16,044			14,661
Industrial		1,688			1,706			1,537			1,621			1,731
Total		36,231			36,607			38,572			39,558			36,479
Transportation:
Commercial		1,637			1,702			1,528			1,849			1,847
Industrial		12,928			12,154			12,375			11,872			12,491
Total		14,565			13,856			13,903			13,721			14,338
Total throughput		50,796			50,463			52,475			53,279			50,817
Degree days * (% of normal)		90.9	%		90.7	%		97.3	%		101.1	%		94.5	%

* 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 loads. 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 obtain 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 and Great Plains has contracted with Northern Natural Gas Company to provide firm storage services that enable both divisions to meet winter peak requirements as well as allow them to better manage their 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 their system natural gas requirements for the next five years.

Regulatory Matters On September 30, 2005, Montana-Dakota filed an application with the MTPSC for a natural gas rate increase. On January 26, 2006, this application was withdrawn as a result of Montana-Dakota’s implementation of cost-reduction measures. In September 2004, Great Plains filed an application with the MPUC for a natural gas rate increase. For additional information regarding Montana-Dakota’s and Great Plains' natural gas rate increase filings, see Item 8 - Financial Statements and Supplementary Data - Note 17.

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 to 28 months from the time such costs are paid. At December 31, 2005, the MTPSC has not issued a final order relative to the last three years of monthly gas cost changes that were implemented on an interim basis. A proceeding is under way and a final ruling is expected by mid-2006.

Montana-Dakota’s North Dakota, South Dakota-Black Hills and South Dakota-East River area natural gas tariffs contain a weather normalization mechanism applicable to firm customers that adjusts the distribution delivery charge revenues to reflect weather fluctuations during the billing period from November 1 through May 1.

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 2005 and do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations in relation to the natural gas distribution operations through 2008.

CONSTRUCTION SERVICES

General MDU Construction 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.

During 2005, the Company acquired construction services businesses in Nevada. None of these acquisitions was material to the Company.

Construction and maintenance crews are active year round. However, activity in certain locations may be seasonal in nature due to the effects of weather.

MDU Construction 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, 2005, MDU Construction Services owned or leased offices in 15 states. This space is used for offices, equipment yards, warehousing, storage and vehicle shops. At December 31, 2005, MDU Construction Services’ net plant investment was approximately $44.3 million.

MDU Construction Services’ 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 December 31, 2005, was approximately $403 million compared to $238 million at December 31, 2004. MDU Construction Services expects to complete a significant amount of this backlog during the year ending December 31, 2006. Due to the nature of its contractual arrangements, in many instances MDU Construction Services’ customers are not committed to the specific volumes of services to be purchased under a contract, but rather MDU Construction Services 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 MDU Construction Services 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 lineworkers in certain areas. MDU Construction Services works with the National Electrical Contractors Association and the IBEW on hiring and recruiting qualified lineworkers.

Competition MDU Construction Services operates in a highly competitive business environment. Most of MDU Construction 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 MDU Construction 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 MDU Construction Services will encounter on any particular project. MDU Construction 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 MDU Construction Services 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. MDU Construction Services relies on repeat customers and strives to maintain successful long-term relationships with these customers.

Environmental Matters MDU Construction Services’ operations are subject to regulation customary for the industry, including federal, state and local environmental compliance. MDU Construction Services believes it is in substantial compliance with these regulations.

The nature of MDU Construction 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. MDU Construction Services currently has no ongoing remediation related to releases from petroleum storage tanks. MDU Construction 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 MDU Construction Services.

MDU Construction Services did not incur any material environmental expenditures in 2005 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2008.

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 27 compressor stations located in the states of Montana, North Dakota, South Dakota and Wyoming. 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 and from Canada. At December 31, 2005, Williston Basin’s net plant investment was approximately $232.8 million. Under the Natural Gas Act, as amended, Williston Basin is subject to the jurisdiction of the FERC regarding certificate, rate, service and accounting matters.

WBI Holdings, through its nonregulated pipeline business, owns and operates gathering facilities in Colorado, Kansas, Montana and Wyoming. A one-sixth interest in the assets of various offshore gathering pipelines and associated onshore pipeline and related processing facilities also is owned by WBI Holdings. These facilities include over 1,800 miles of field gathering lines and 80 owned or leased compression facilities, some of which interconnect with Williston Basin’s system. In addition, WBI Holdings provides installation sales and/or leasing of alternate energy delivery systems, primarily propane air facilities, as well as provides 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, producers, 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. WBI Holdings currently estimates that it can adequately meet the requirements of these contracts. WBI Holdings transacts a significant portion of its pipeline and energy services business in the northern Great Plains and Rocky Mountain regions of the United States.

Another energy services business owned by WBI Holdings is Innovatum, a cable and pipeline magnetization and locating company. Innovatum provides products and services that assist the natural gas and oil and telecommunication industries with accurate location and tracking of buried pipelines and cables on a worldwide basis. Additionally, Innovatum manufactures and sells a line of terrestrial, hand-held locators that are used for locating and identifying underground objects. Innovatum has 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. For additional information regarding Innovatum, see Item 8 - Financial Statements and Supplementary Data - Note 3.

System Demand and Competition Williston Basin competes with several pipelines for its customers' transportation, storage and gathering 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, serve 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, 2005, represented 68 percent of Williston Basin's currently subscribed firm transportation capacity. Montana-Dakota has a firm transportation agreement with Williston Basin for a term of five years expiring in June 2007. In addition, Montana-Dakota has a contract with Williston Basin to provide firm storage services to facilitate meeting Montana-Dakota's winter peak requirements for a term of 20 years expiring in July 2015.

System Supply Williston Basin's underground natural gas storage facilities have a certificated storage capacity of approximately 353 Bcf, including 193 Bcf of working gas capacity, 85 Bcf of cushion gas and 75 Bcf of native gas. The native gas includes an estimated 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 certain 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 nontraditional and 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 1A - Risk Factors - Environmental and Regulatory Risks and Item 3 - Legal Proceedings. 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, gathering and storage services through system expansion and/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. For additional information regarding Williston Basin’s general natural gas rate change application, see Item 8 - Financial Statements and Supplementary Data - Note 17.

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 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 FERC’s permitting processes for both the construction and abandonment of Williston Basin's natural gas transmission pipelines and storage facilities.

WBI Holdings' pipeline and energy services operations did not incur any material environmental expenditures in 2005 and do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2008.

NATURAL GAS AND OIL PRODUCTION

General 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 and oil production properties. Fidelity shares revenues and expenses from the development of specified properties in proportion to its ownership interests. Fidelity’s business is focused in three core regions: Rocky Mountain, Offshore Gulf of Mexico, and Mid-Continent/Gulf States.

Rocky Mountain

Fidelity’s properties in this region are primarily located in the states of Colorado, Montana, North Dakota and Wyoming. Fidelity owns in fee or holds natural gas and oil leases for the properties it operates that 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 the Powder River Basin of Montana and Wyoming. Fidelity also owns nonoperated natural gas and oil interests in this region.

Offshore Gulf of Mexico

Fidelity has nonoperated interests throughout the Offshore Gulf of Mexico. These interests are primarily located in the shallow waters off the coasts of Texas and Louisiana.

Mid-Continent/Gulf States

This region includes properties in Alabama, Louisiana, New Mexico, Oklahoma and Texas. In 2005, Fidelity acquired natural gas and oil production properties in southern Texas. The acquisition was not material to the Company. Fidelity owns in fee or holds natural gas and oil leases for the properties it operates that are in the Tabasco and Texan Gardens fields of Texas. In addition, Fidelity owns several nonoperated interests in this region.

Fidelity continues to seek additional reserve and production growth opportunities through the direct acquisition of producing properties, through the 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 for 2005, 2004 and 2003, are as follows:

	2005		2004		2003
Natural gas:
Production (MMcf)		59,378		59,750		54,727
Average realized price per Mcf (including hedges)	$	6.11	$	4.69	$	3.90
Average realized price per Mcf (excluding hedges)	$	6.87	$	4.90	$	4.28
Oil:
Production (MBbls)		1,707		1,747		1,856
Average realized price per barrel (including hedges)	$	42.59	$	34.16	$	27.25
Average realized price per barrel (excluding hedges)	$	48.73	$	37.75	$	28.42
Production costs, including taxes, per net equivalent Mcf:
Lease operating costs	$	.56	$	.47	$	.48
Gathering and transportation		.20		.17		.22
Production and property taxes		.50		.32		.32
	$	1.26	$	.96	$	1.02

2005 annual net production by region is as follows:

	Natural
	Gas			Oil			Total			Percent of
Region		(MMcf	)		(MBbls	)		(MMcfe	)		Total
Rocky Mountain		45,768			1,009			51,819			74	%
Offshore Gulf of Mexico		7,189			296			8,967			13
Mid-Continent/Gulf States		6,421			402			8,836			13
Total		59,378			1,707			69,622			100	%

Well and Acreage Information Gross and net productive well counts and gross and net developed and undeveloped acreage related to interests at December 31, 2005, are as follows:

	Gross*		Net**
Productive wells:
Natural gas		3,444		2,758
Oil		2,251		135
Total		5,695		2,893
Developed acreage (000's)		790		364
Undeveloped acreage (000's)		926		416

* Reflects well or acreage in which an interest is owned.

** Reflects Fidelity’s percentage ownership.

Exploratory and Development Wells The following table reflects activities relating to Fidelity’s natural gas and oil wells drilled and/or tested during 2005, 2004 and 2003:

	Net Exploratory						Net Development
	Productive		Dry Holes		Total		Productive		Dry Holes		Total		Total
2005		2		3		5		312		25		337		342
2004		1		4		5		230		20		250		255
2003		10		2		12		274		2		276		288

At December 31, 2005, there were 239 gross wells in the process of drilling or under evaluation, 224 of which were development wells and 15 of which were exploratory wells. These wells are not included in the previous table. Fidelity expects to complete drilling and testing the majority of these wells within the next 12 months.

The information in the table above should not be considered indicative of future performance nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons whether or not they produce a reasonable rate of return.

Competition The natural gas and oil industry is highly competitive. Fidelity competes with a substantial number of major and independent natural gas and oil companies in acquiring producing properties and new leases for future exploration and development, and in securing the equipment and expertise necessary to explore, develop and operate its properties. Some of Fidelity’s competitors have greater financial and operational resources than Fidelity.

Environmental Matters Fidelity’s natural gas and oil production operations are generally subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations. Fidelity 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 incidental 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 2005, capital expenditures for water handling in compliance with current laws and regulations were approximately $110,000 and are estimated to be approximately $2.0 million, $1.2 million and $1.0 million in 2006, 2007 and 2008, respectively. For information regarding coalbed natural gas legal proceedings, see Item 1A - Risk Factors, Item 3 - Legal Proceedings and Item 8 - Financial Statements and Supplementary Data - Note 18.

Reserve Information Fidelity's recoverable proved developed and undeveloped natural gas and oil reserves by region at December 31, 2005, are as follows:

Region	Natural Gas (MMcf)		Oil (MBbls)		Total (MMcfe)		Percent of Total		PV-10 Value * (in millions)
Rocky Mountain		385,800		15,000		475,600		77%	$	1,597.5
Offshore Gulf of Mexico		14,700		800		19,400		3		136.4
Mid-Continent/Gulf States		88,600		5,400		121,400		20		415.7
Total reserves		489,100		21,200		616,400		100%	$	2,149.6

* PV - 10 value represents the discounted future net cash flows attributable to proved natural gas and oil reserves before income taxes, discounted at 10 percent. The standardized measure of discounted future net cash flows at Item 8 - Financial Statements and Supplementary Data - Supplementary Financial Information represents the present value of future cash flows attributable to proved natural gas and oil reserves after income taxes, discounted at 10 percent.

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

General Knife River operates construction materials and mining businesses headquartered in Alaska, California, Hawaii, Idaho, 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, most 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 2005, the Company acquired several construction materials and mining businesses with operations in Idaho, Iowa and Oregon. None of these acquisitions were material to the Company.

Knife River continues to investigate the acquisition of other construction materials properties, particularly those relating to construction aggregates and related products such as ready-mixed concrete, asphalt and related construction services.

On August 10, 2005, a new transportation bill called the SAFETEA-LU was signed into law. SAFETEA-LU represents a 31 percent increase over previous funding levels. SAFETEA-LU will provide funding through September 2009. Knife River expects to see average annual funding increases in each of its states of operation ranging from a high of 46 percent in Minnesota to a low of 19 percent in Hawaii. Alaska, Idaho, Montana, North Dakota, Oregon and Wyoming will each see average annual funding increases of slightly more than 30 percent. California will receive a 34 percent average annual increase while Iowa will receive a 25 percent increase and Texas will receive a 37 percent increase.

The construction materials business had approximately $465 million in backlog at December 31, 2005, compared to $426 million at December 31, 2004. The Company anticipates that a significant amount of the current backlog will be completed during the year ending December 31, 2006.

Competition Knife River's construction materials products are marketed under highly competitive conditions. Price is the principal competitive force to which these products are subject, with service, quality, 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 that 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 effect 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 also are 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 1.2 billion tons of the 1.3 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, 2005, and sales as of and for the years ended December 31, 2005, 2004 and 2003:

	Number of Sites				Number of Sites										Estimated
	(Crushed Stone)				(Sand & Gravel)				Tons Sold (000's)						Reserves				Reserve
Production Area	owned		leased		owned		leased		2005		2004		2003		(000’s tons)		Lease Expiration		Life (years)
Central MN		---		1		52		70		4,608		6,429		6,265		111,156		2006-2028		24
Portland, OR		1		4		5		3		5,559		5,821		4,610		266,267		2006-2055		48
Northern CA		1		---		7		1		4,180		3,699		3,907		54,089		2046		13
Southwest OR		4		8		12		5		3,892		3,405		3,360		123,340		2006-2031		32
Eugene, OR		3		3		4		2		2,009		2,003		1,442		183,642		2006-2046		91
Hawaii		---		6		---		---		2,891		2,460		2,134		74,279		2011-2037		26
Central MT		---		---		5		1		2,408		2,555		2,667		35,112		2023		15
Anchorage, AK		---		---		1		---		1,307		1,473		1,610		21,973		N/A		17
Northwest MT		---		---		8		5		1,679		1,810		1,413		28,349		2006-2020		17
Southern CA		---		2		---		---		166		518		1,945		95,644		2035		Over 100
Bend, OR/Boise, ID		1		2		5		2		1,731		1,678		857		104,673		2010-2012		60
Northern MN		2		---		21		20		968		853		873		32,886		2006-2016		34
Northern IA/ Southern MN		18		10		8		26		2,063		1,370		---		68,739		2006-2017		33
North/South Dakota		---		---		2		59		1,205		965		704		55,604		2006-2031		46
Eastern TX		1		2		---		3		1,255		1,067		449		16,960		2006-2012		14
Casper, WY		---		---		---		1		2		291		172		983		2006		Over 100
Sales from other sources										11,281		7,047		6,030		---
										47,204		43,444		38,438		1,273,696

The 1.3 billion tons of estimated aggregate reserves at December 31, 2005, is comprised of 554 million tons that are owned and 720 million tons that are leased. The leases have various expiration dates ranging from 2006 to 2055. Approximately 54 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 21 years, including options for renewal that are at Knife River’s discretion. Based on 2005 sales from leased reserves, the average time necessary to produce remaining aggregate reserves from such leases is approximately 47 years.

The following table summarizes Knife River’s aggregate reserves at December 31, 2005, 2004 and 2003, and reconciles the changes between these dates:

	2005			2004			2003
	(000’s of tons)
Aggregate reserves:
Beginning of year		1,257,498			1,181,413			1,110,020
Acquisitions		53,495			115,965			109,362
Sales volumes*		(35,923	)		(36,397	)		(32,408	)
Other		(1,374	)		(3,483	)		(5,561	)
End of year		1,273,696			1,257,498			1,181,413
* Excludes sales from other sources.

Lignite Deposits The Company has lignite deposits and leases at its former Gascoyne Mine site in North Dakota. These lignite deposits are currently not being mined and are not associated with an operating mine. The 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, 2005, Knife River had under ownership or lease, deposits of approximately 11.4 million tons of recoverable lignite coal.

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 to what may be ultimately determined with regard to the Portland, Oregon, Harbor Superfund Site issue described later, 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 also are subject to these laws. In most of the states where Knife River operates, these regulatory programs have been delegated to state and local regulatory authorities. Knife River's facilities also are subject to RCRA as it applies to underground storage tanks and the management of petroleum hydrocarbon products and wastes. These programs also have 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 Corps 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 also are occasionally subject to the 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 or an asphalt or concrete plant. 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 also are subject to state and federal cultural resources protection laws when new areas are disturbed for plants or mining operations. Land use permit applications generally require that areas proposed for mining or other surface disturbances 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 land use 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 land use permits 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 and other land use permit approvals so that sufficient permitted reserves are available to support its operations. For mining operations, this often requires considerable advanced planning to ensure sufficient time is available to complete the permitting process before the newly permitted aggregate 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 SMCRA, as well as the North Dakota Surface Mining Act. Portions of the Gascoyne mine remain under reclamation bond until the 10-year revegetation liability period has expired. A portion of the original permit has been released from bond and additional areas are currently in the process of having the bond released. Knife River’s intention is to request bond release as soon as it is deemed possible with all final bond release applications being filed by 2013.

Knife River did not incur any material environmental expenditures in 2005 and, except as to what may be ultimately determined with regard to the issue described below, Knife River does not expect to incur any material expenditures related to environmental compliance with current laws and regulations through 2008.

In December 2000, MBI 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 cleanup of the property site, see Item 3 - Legal Proceedings.

INDEPENDENT POWER PRODUCTION

General Centennial Resources owns, builds and operates electric generating facilities in the United States and has investments in domestic and international natural resource-based projects. Electric capacity and energy produced at its power plants primarily are sold under mid- and long-term contracts to nonaffiliated entities.

Competition Centennial Resources encounters competition in the development of new electric generating plants and the acquisition of existing generating facilities, as well as operation and maintenance services. Competitors include nonutility 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. Factors for competing in the power production industry may include having a balanced portfolio of generating assets, fuel types, customers and power sales agreements and maintaining low production costs.

Domestic

Centennial Power owns 213 MW of natural gas-fired electric generating facilities near Brush, Colorado. The Brush Generating Facility was purchased in November 2002. Substantially all of the Brush Generating Facility’s output is sold to PSCo, a wholly owned subsidiary of Xcel Energy. A power purchase agreement with PSCo for 138 MW expires in September 2012. In December 2005, Centennial Power entered into two successive purchase power agreements with PSCo for the sale of 75 MW of capacity and energy. One purchase power agreement expires in April 2007 followed by a 10-year agreement expiring in April 2017. The Brush Generating Facility is operated by CEM. PSCo is under contract to supply natural gas to the Brush Generating Facility during the terms of the power purchase agreements.

Centennial Power owns a 66.6-MW wind-powered electric generating facility in the San Gorgonio Pass, northwest of Palm Springs, California. This facility was purchased in January 2003. The facility sells all of its output under an agreement with the California Department of Water Resources, which expires in September 2011. AES SeaWest, Inc. is under a contract to operate the facility. The contract with AES SeaWest, Inc. expires in October 2013.

Centennial Resources, through indirect wholly owned subsidiaries, has a 50-percent ownership interest in Hartwell, which owns a 310-MW natural gas-fired electric generating facility near Hartwell, Georgia. This ownership interest was purchased in September 2004. The Hartwell Generating Facility sells its output under a power purchase agreement with Oglethorpe that expires in May 2019. Oglethorpe reimburses the Hartwell Generating Facility for actual costs of fuel required to operate the plant. American National Power, a wholly owned subsidiary of International Power of the United Kingdom, holds the remaining 50-percent ownership interest and is the operating partner for the facility.

Centennial Power constructed a 116-MW coal-fired electric generating facility near Hardin, Montana. The Hardin Generating Facility is projected to be on line in early 2006. A power sales agreement with Powerex Corp., a subsidiary of BC Hydro, has been secured for the entire output of the plant for a term expiring October 31, 2008, with the purchaser having an option for a two-year extension. Coal for the Hardin Generating Facility is supplied by Westmoreland, at contracted pricing, through a coal sales agreement that expires in December 2008, with the Company having an option of a two-year extension. The Hardin Generating Facility is operated by CEM.

CEM provides analysis, design, construction, refurbishment, and operation and maintenance services to independent power producers. CEM is headquartered in Lafayette, Colorado, and was acquired in April 2004. In addition to operating the Brush and Hardin facilities, CEM provides operation and maintenance services for third-party customers owning approximately 510 MW of generating capacity at December 31, 2005. The operation and maintenance contracts have expirations ranging from January 2007 to June 2009.

Environmental Matters Centennial Power has several operations that require federal and state environmental permits. The Brush Generating Facility, Hartwell Generating Facility and Hardin Generating Facility 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. Centennial Power believes it is in substantial compliance with these regulations.

The Brush Generating Facility has a Title V Operating Permit issued by the state for a period of five years under a program approved by the EPA. The facility 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 Generating Facility is operating in compliance with the agreement.

The Hartwell and Hardin Generating Facilities have Title V Operating Permits issued by the applicable state for a period of five years under a program approved by the EPA. Centennial Power believes it is in substantial compliance with these regulations.

The Mountain View wind-powered electric generating facility has obtained necessary siting authority and 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.

In August 2004, CPP and BIV were each issued a draft Compliance Order on Consent by the CDPHE. The Compliance Orders on Consents were issued in connection with excess emission periods of nitrogen oxides and carbon monoxide at the Company’s electric generating facilities in Brush, Colorado, occurring mainly during start-up and shut-down periods. In June 2005, CPP, BIV and the CDPHE agreed upon the Compliance Orders on Consents. The terms of the Compliance Orders on Consents for CPP and BIV include administrative penalties of $9,900 and $10,600, and noncompliance/economic benefit penalties of $7,700 and $8,300, respectively. In addition, the terms of the Compliance Orders on Consents include an agreement by CPP and BIV to make nontax-deductible donations for Supplemental Environmental Projects in Morgan County, Colorado, with total expenditures of not less than $39,600 and $42,400, respectively. In October 2005, CPP, BIV and the CDPHE agreed upon three Supplemental Environmental Projects to be funded.

Centennial Power does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2008 in connection with its existing operations.

International

MDU Brasil was a party to a joint venture agreement with a Brazilian firm under which the parties agreed to develop electric generation and transmission, steam generation and coal mining projects in Brazil. The Company’s 49 percent interest in MPX was sold in June 2005. For information regarding the sale of MPX, see Item 8 - Financial Statements and Supplementary Data - Note 2. In November 2005, the joint venture relationship was terminated.

Centennial International owns 49.99 percent of Carib Power. Carib Power was acquired in February 2004. Carib Power, through a wholly owned subsidiary, owns a 225-MW natural gas-fired electric generating facility in Trinidad and Tobago. The Trinity Generating Facility sells its output to the T&TEC, the governmental entity responsible for the transmission, distribution and administration of electrical power to the national electrical grid of Trinidad and Tobago. The power purchase agreement expires in September 2029. T&TEC also is under contract to supply natural gas to the Trinity Generating Facility during the term of the power purchase agreement.

For additional information regarding international operations, see Item 1A - Risk Factors - Risks Relating to Foreign Operations.

Environmental Matters The Trinity Generating Facility has been designed to comply with Trinidad and Tobago environmental requirements. The facility operates in documented conformance with these applicable environmental regulations and permit requirements. Trinity Generating Facility is in material compliance with all applicable environmental regulations and permit requirements.

This business segment’s international operations did not incur any material environmental expenditures in 2005 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2008.

ITEM 1A. RISK FACTORS

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.

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 Item 7 - MD&A - Prospective Information. All these subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, also are 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 and pipeline and energy services businesses are dependent on factors, including commodity prices and commodity price basis differentials, that cannot be predicted or controlled.

These factors include: fluctuations in natural gas and crude oil prices; fluctuations in commodity price basis differentials; availability of economic supplies of natural gas; drilling successes in natural gas and oil operations; the timely receipt of necessary permits and approvals; 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. Significant changes in these factors could negatively affect the results of operations and financial condition of the Company’s natural gas and oil production and pipeline and energy services businesses.

The construction, startup and operation of power generation facilities may involve unanticipated changes or delays that could negatively impact the Company’s business and its results of operations.

The construction, startup and operation of power generation facilities involves many risks, including delays; breakdown or failure of equipment; competition; inability to obtain required governmental permits and approvals; inability to negotiate acceptable acquisition, construction, fuel supply, off-take, transmission or other material agreements; changes in market price for power; cost increases; as well as the risk of performance below expected levels of output or efficiency. Such unanticipated events could negatively impact the Company’s business and its results of operations.

The Company’s 116-MW coal-fired electric generating facility near Hardin, Montana, is projected to be on line in early 2006. Increases in the cost of construction, startup or operational expenses could negatively affect the independent power production business and its results of operations.

Economic volatility affects the Company’s operations, as well as the demand for its products and services and, as a result, may have a negative impact on the Company’s future revenues.

The global demand for natural resources, interest rates, governmental budget constraints and the ongoing threat of terrorism can create volatility in the financial markets. 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.

The Company relies on financing sources and capital markets. If the Company is unable to obtain economic 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 sources of liquidity for capital requirements not satisfied by its 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

·	A deterioration in capital market conditions

·	Volatility in commodity prices

·	Terrorist attacks

Environmental and Regulatory Risks

Some of the Company’s operations are subject to extensive environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the Company to environmental liabilities.

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, and delays as a result of ongoing litigation and administrative proceedings and 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 injunctive relief or other remedies to enforce applicable environmental laws and regulations. The Company cannot predict the outcome (financial or operational) of any related litigation or administrative proceedings 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.

One of the Company’s subsidiaries is subject to ongoing litigation and administrative proceedings in connection with its coalbed natural gas development activities. These proceedings have caused delays in coalbed natural gas drilling activity, and the ultimate outcome of the actions could have a material effect on existing coalbed natural gas operations and/or the future development of its coalbed natural gas properties.

Fidelity has been named as a defendant in, and/or certain of its operations are or have been the subject of, more than a dozen 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.

Rulemaking proceedings to create rules related to the re-injection of water and water treatment and to amend the nondegradation policy in connection with coalbed natural gas development have been initiated by the BER. If the rules are adopted as proposed, they could have a material effect on Fidelity’s existing coalbed natural gas operations.

The Company is subject to extensive government regulations that may delay and/or 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 Foreign Operations

The value of the Company’s investments in operations may diminish because of political, regulatory and economic conditions in countries where the Company does business.

The Company is subject to political, regulatory and economic conditions 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.

Other Risks

Weather conditions can adversely affect the Company’s operations and revenues, as evidenced by the hurricanes in the Gulf Coast region in 2005 causing some reduction in natural gas and oil production.

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 construction services and construction materials and mining businesses and affect ongoing operation and maintenance and construction and drilling activities for the pipeline and energy services and natural gas and oil production businesses. In addition, severe weather can be destructive, causing outages, reduced natural gas and oil production, 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.

Competition is increasing in all of the Company’s businesses.

All of the Company’s businesses are subject to increased competition. The independent power production industry has many competitors in the operation, acquisition and development of power generation facilities. Construction 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, increased natural gas prices 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. The increase in competition could negatively affect the Company’s results of operations and financial condition.

Other factors that could impact the Company’s businesses.

The following are other factors that should be considered for a better understanding of the financial condition of the Company. These other factors may impact the Company’s financial results in future periods.

Acquisition, disposal and impairments of assets or facilities

Changes in operation, performance and construction of plant facilities or other assets

Changes in present or prospective generation

The availability of economic expansion or development opportunities

Population growth rates and demographic patterns

Market demand for, and/or available supplies of, energy- and construction-related products and services

Cyclical nature of large construction projects at certain operations

Changes in tax rates or policies

Unanticipated project delays or changes in project costs (including related energy costs)

Unanticipated changes in operating expenses or capital expenditures

Labor negotiations or disputes

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 or regulatory proceedings

The ability to effectively integrate the operations and the internal controls of acquired companies

The ability to attract and retain skilled labor and key personnel

ITEM 1B. UNRESOLVED COMMENTS

The Company has no unresolved comments with the SEC.

ITEM 3. LEGAL PROCEEDINGS

Litigation

Royalties Case In June 1997, Grynberg filed suit under the Federal False Claims Act against Williston Basin and Montana-Dakota. Grynberg also filed more than 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. All cases were consolidated in the Wyoming Federal District Court.

In June 2004, following preliminary discovery, Williston Basin and Montana-Dakota joined with other defendants and filed a Motion to Dismiss on the ground that the information upon which Grynberg based his complaint was publicly disclosed prior to the filing of his complaint and further, that he is not the original source of such information. The Motion to Dismiss was heard on March 17 and 18, 2005, by the Special Master appointed by the Wyoming Federal District Court. The Special Master, in his Written Report dated May 13, 2005, recommended that the lawsuit be dismissed against certain defendants, including Williston Basin and Montana-Dakota. A hearing on the adoption of the Written Report was held on December 9, 2005, before the Wyoming Federal District Court.

In the event the Motion to Dismiss is not granted, it is expected that further discovery will follow. Williston Basin and Montana-Dakota believe Grynberg will not prevail in the suit or recover damages from Williston Basin and/or Montana-Dakota because insufficient facts exist to support the allegations. Williston Basin and Montana-Dakota believe Grynberg’s claims are without merit and intend to vigorously contest this suit.

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.

Coalbed Natural Gas Operations Fidelity has been named as a defendant in, and/or certain of its operations are or have been the subject of, more than a dozen 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 November 2004 by a number of environmental organizations, including the NPRC and the Montana Environmental Information Center, as well as the Tongue River Water Users' Association and the Northern Cheyenne Tribe. Portions of two of the lawsuits have been transferred to the Wyoming Federal District Court. 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, the NEPA, the Federal Land Management Policy Act, the NHPA and the Montana Environmental Policy Act. The cases involving alleged violations of the Clean Water Act have been resolved without a finding that Fidelity is in violation of the Clean Water Act. There presently are no claims pending for penalties, fines or damages under the Clean Water Act. The suits that remain extant include a variety of claims that state and federal government agencies violated various environmental laws that impose procedural requirements and the lawsuits seek injunctive relief, invalidation of various permits and unspecified damages.

In suits filed in the Montana Federal District Court, the NPRC and the Northern Cheyenne Tribe asserted that further development by Fidelity and others of coalbed natural gas in Montana should be enjoined until the BLM completes a SEIS. The Montana Federal District Court, in February 2005, entered a ruling requiring the BLM to complete a SEIS. The Montana Federal District Court later entered an order that would have allowed limited coalbed natural gas development in the Powder River Basin in Montana pending the BLM's preparation of the SEIS. The plaintiffs appealed the decision to the Ninth Circuit. The Montana Federal District Court declined to enter an injunction requested by the NPRC and the Northern Cheyenne Tribe that would have enjoined development pending the appeal. In late May 2005, the Ninth Circuit granted the request of the NPRC and the Northern Cheyenne Tribe and, pending further order from the Ninth Circuit, enjoined the BLM from approving any new coalbed natural gas development projects in the Powder River Basin in Montana. That court also enjoined Fidelity from drilling any additional federally permitted wells in its Montana Coal Creek Project and from constructing infrastructure to produce and transport coalbed natural gas from the Coal Creek Project's existing federal wells. The matter has been fully briefed and argued before the Ninth Circuit and the parties are awaiting a decision of the court.

In related actions in the Montana Federal District Court, the NPRC and the Northern Cheyenne Tribe asserted, among other things, that the actions of the BLM in approving Fidelity's applications for permits and the plan of development for the Badger Hills Project in Montana did not comply with applicable Federal laws, including the NHPA and the NEPA. The NPRC also asserted that the Environmental Assessment that supported the BLM's prior approval of the Badger Hills Project was invalid. On June 6, 2005, the Montana Federal District Court issued orders in these cases enjoining operations on Fidelity's Badger Hills Project pending the BLM's consultation with the Northern Cheyenne Tribe as to satisfaction of the applicable requirements of NHPA and a further environmental analysis under NEPA. Fidelity has sought and obtained stays of the injunctive relief from the Montana Federal District Court and production from Fidelity’s Badger Hills Project continues. On September 2, 2005, the Montana Federal District Court entered an Order based on a stipulation between the parties to the NPRC action that production from existing wells in Fidelity’s Badger Hills Project may continue pending preparation of a revised environmental analysis. On November 1, 2005, the Montana Federal District Court entered an Order based on a stipulation between the parties to the Northern Cheyenne Tribe action that production from existing wells in Fidelity’s Badger Hills Project may continue pending preparation of a revised environmental analysis. On December 16, 2005, Fidelity filed a Notice of Appeal to the Ninth Circuit.

The NPRC has filed a petition with the BER and the BER has initiated related rulemaking proceedings to create rules that would, if promulgated, require re-injection of water produced in connection with coalbed natural gas operations and treatment of such water in the event re-injection is not feasible and amend the nondegradation policy in connection with coalbed natural gas development. If the rules are adopted as proposed, it is possible that an adverse impact on Fidelity’s operations could result. At this point, the Company cannot predict the outcome of the rulemaking process before the BER or its impact on the Company’s operations.

Fidelity is vigorously defending its interests in all coalbed-related lawsuits and related actions in which it is involved, including the Ninth Circuit injunction. In those cases where damage claims have been asserted, Fidelity is unable to quantify the damages sought and will be unable to do so until after the completion of discovery. 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 this resource in the affected regions.

Electric Operations Montana-Dakota has joined with two electric generators in appealing a finding by the ND Health Department in September 2003 that the ND Health 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 ND Health 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 in October 2003 in the Burleigh County District Court in Bismarck, North Dakota. Proceedings have been stayed pending discussions with the EPA, the ND Health Department and the other electric generators. The Company cannot predict the outcome of the ND Health Department matter or its ultimate impact on its operations.

Natural Gas Storage Williston Basin filed suit on January 27, 2006, seeking to recover unspecified damages from Anadarko and its wholly owned subsidiary, Howell, and to enjoin Anadarko’s and Howell’s present and future operations in and near Williston Basin’s Elk Basin Storage Reservoir located in Wyoming and Montana. Based on relevant information, including reservoir and well pressure data, it appears that reservoir pressure has decreased and that quantities of gas may have been diverted by Anadarko’s and Howell’s drilling and production activities in areas within and near the boundaries of Williston Basin’s Elk Basin Storage Reservoir. Williston Basin is seeking not only to recover damages for the gas that has been diverted, but to prevent further drainage of its storage reservoir. Williston Basin is also assessing further avenues for recovery through the regulatory process at the FERC. Because of the very preliminary stage of the legal proceedings, Williston Basin cannot estimate the size of any potential loss or recovery, or the likelihood of obtaining injunctive relief or recovery through the regulatory process.

Environmental matters

Portland Harbor Site In December 2000, MBI 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 DEQ are being recorded and initially paid, through an administrative consent order, by the 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 later in 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 the sale agreement under which MBI acquired the property.

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.

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 2005.

PART II

ITEM 5.

MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASE OF EQUITY SECURITIES

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 2005 and 2004 and dividends declared thereon were as follows:

					Common
	Common		Common		Stock
	Stock Price		Stock Price		Dividends
	(High)		(Low)		Per Share
2005
First quarter	$	28.50	$	25.48	$	.18
Second quarter		29.34		26.35		.18
Third quarter		36.07		28.08		.19
Fourth quarter		37.13		30.85		.19
					$	.74

2004
First quarter	$	24.35	$	22.67	$	.17
Second quarter		24.03		21.85		.17
Third quarter		26.43		23.72		.18
Fourth quarter		27.70		25.20		.18
					$	.70

As of December 31, 2005, the Company's common stock was held by approximately 15,200 stockholders of record.

Between October 1, 2005, and December 31, 2005, the Company issued 2,860 shares of Common Stock, $1.00 par value, and the Preference Share Purchase Rights appurtenant thereto, as part of the consideration paid by the Company in the acquisition of a business in a prior period. The Common Stock and Rights issued by the Company in this transaction 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

Operating Statistics	2005			2004			2003			2002			2001			2000
Selected Financial Data
Operating revenues (000's):
Electric	$	181,238		$	178,803		$	178,562		$	162,616		$	168,837		$	161,621
Natural gas distribution		384,199			316,120			274,608			186,569			255,389			233,051
Construction services		687,125			426,821			434,177			458,660			364,750			169,382
Pipeline and energy services		480,294			357,229			252,192			165,258			531,114			636,848
Natural gas and oil production		439,367			342,840			264,358			203,595			209,831			138,316
Construction materials and mining		1,604,610			1,322,161			1,104,408			962,312			806,899			631,396
Independent power production		48,508			43,059			32,261			2,998			---			---
Other		6,038			4,423			2,728			3,778			---			---
Intersegment eliminations		(375,965	)		(272,199	)		(191,105	)		(114,249	)		(113,188	)		(96,943	)
	$	3,455,414		$	2,719,257		$	2,352,189		$	2,031,537		$	2,223,632		$	1,873,671
Operating income (000's):
Electric	$	29,038		$	26,776		$	35,761		$	33,915		$	38,731		$	38,743
Natural gas distribution		7,404			1,820			6,502			2,414			3,576			9,530
Construction services		28,171			(5,757	)		12,885			13,980			25,199			16,606
Pipeline and energy services		42,376			24,690			35,155			39,091			30,368			28,782
Natural gas and oil production		230,383			178,897			118,347			85,555			103,943			66,510
Construction materials and mining		105,318			86,030			91,579			91,430			71,451			56,816
Independent power production		4,916			8,126			10,610			(1,176	)		---			---
Other		420			136			1,233			908			---			---
	$	448,026		$	320,718		$	312,072		$	266,117		$	273,268		$	216,987
Earnings on common stock (000's):
Electric	$	13,940		$	12,790		$	16,950		$	15,780		$	18,717		$	17,733
Natural gas distribution		3,515			2,182			3,869			3,587			677			4,741
Construction services		14,558			(5,650	)		6,170			6,371			12,910			8,607
Pipeline and energy services		22,092			8,944			18,158			19,097			16,406			10,494
Natural gas and oil production		141,625			110,779			70,767*			53,192			63,178			38,574
Construction materials and mining		55,040			50,707			54,261*			48,702			43,199			30,113
Independent power production		22,921			26,309			11,415			307			---			---
Other		707			321			606			652			---			---
Earnings on common stock before
cumulative effect of accounting change		274,398			206,382			182,196*			147,688			155,087			110,262
Cumulative effect of accounting change		---			---			(7,589	)		---			---			---
	$	274,398		$	206,382		$	174,607		$	147,688		$	155,087		$	110,262
Earnings per common share before
cumulative effect of accounting change - diluted	$	2.29		$	1.76		$	1.62*		$	1.38		$	1.52		$	1.20
Cumulative effect of accounting change		---			---			(.07	)		---			---			---
	$	2.29		$	1.76		$	1.55		$	1.38		$	1.52		$	1.20
Pro forma amounts assuming retroactive
application of accounting change:
Net income (000's)	$	275,083		$	207,067		$	182,913		$	146,052		$	152,933		$	108,951
Earnings per common share - diluted	$	2.29		$	1.76		$	1.62		$	1.36		$	1.49		$	1.17
Common Stock Statistics
Weighted average common shares
outstanding - diluted (000's)		119,660			117,411			112,460			106,863			101,803			92,085
Dividends per common share	$	.7400		$	.7000		$	.6600		$	.6266		$	.6000		$	.5733
Book value per common share	$	15.65		$	14.09		$	12.66		$	11.56		$	10.60		$	9.03
Market price per common share (year end)	$	32.74		$	26.68		$	23.81		$	17.21		$	18.77		$	21.67
Market price ratios:
Dividend payout		32	%		40	%		43	%		45	%		39	%		48	%
Yield		2.3	%		2.7	%		2.9	%		3.7	%		3.3	%		2.7	%
Price/earnings ratio		14.3x			15.2x			15.4x			12.5x			12.3x			18.1x
Market value as a percent of book value		209.2	%		189.4	%		188.1	%		148.8	%		177.0	%		239.9	%
Profitability Indicators
Return on average common equity		15.7	%		13.2	%		13.0	%		12.5	%		15.3	%		14.3	%
Return on average invested capital		10.8	%		9.4	%		8.9	%		8.6	%		10.1	%		9.5	%
Interest coverage		10.2x			7.1x			7.4x			7.7x			8.5x			8.3x
Fixed charges coverage, including
preferred dividends		6.1x			4.7x			4.7x			4.8x			5.3x			4.1x

General
Total assets (000's)	$	4,423,562		$	3,733,521		$	3,380,592		$	2,996,921		$	2,675,978		$	2,358,981
Long-term debt, net of current maturities (000's)	$	1,104,752		$	873,441		$	939,450		$	819,558		$	783,709		$	728,166
Redeemable preferred stock (000's)	$	---		$	---		$	---		$	1,300		$	1,400		$	1,500
Capitalization ratios:
Common equity		63	%		65	%		60	%		60	%		58	%		54	%
Preferred stocks		---			1			1			1			1			1
Long-term debt, net of current maturities		37			34			39			39			41			45
		100	%		100	%		100	%		100	%		100	%		100	%

* Before cumulative effect of the change in accounting for asset retirement obligations required by the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations,” as discussed in Item 8 - Financial Statements and Supplementary Data - Notes 1 and 8.

NOTE: Common stock share amounts reflect the Company’s three-for-two common stock split effected in October 2003.

Electric
Retail sales (thousand kWh)		2,413,704			2,303,460			2,359,888			2,275,024			2,177,886			2,161,280
Sales for resale (thousand kWh)		615,220			821,516			841,637			784,530			898,178			930,318
Electric system summer generating and firm purchase capability - kW (Interconnected system)		546,085			544,220			542,680			500,570			500,820			500,420
Demand peak - kW
(Interconnected system)		470,470			470,470			470,470			458,800			453,000			432,300
Electricity produced (thousand kWh)		2,327,228			2,552,873			2,384,884			2,316,980			2,469,573			2,331,188
Electricity purchased (thousand kWh)		892,113			794,829			929,439			857,720			792,641			948,700
Average cost of fuel and purchased
power per kWh	$	.020		$	.019		$	.019		$	.018		$	.018		$	.016
Natural Gas Distribution
Sales (Mdk)		36,231			36,607			38,572			39,558			36,479			36,595
Transportation (Mdk)		14,565			13,856			13,903			13,721			14,338			14,314
Weighted average degree days -
% of previous year's actual		100	%		94	%		96	%		109	%		95	%		113	%
Pipeline and Energy Services
Transportation (Mdk)		104,909			114,206			90,239			99,890			97,199			86,787
Gathering (Mdk)		82,111			80,527			75,861			72,692			61,136			41,717
Natural Gas and Oil Production
Production:
Natural gas (MMcf)		59,378			59,750			54,727			48,239			40,591			29,222
Oil (MBbls)		1,707			1,747			1,856			1,968			2,042			1,882
Average realized prices (including hedges):
Natural gas (per Mcf)	$	6.11		$	4.69		$	3.90		$	2.72		$	3.78		$	2.90
Oil (per barrel)	$	42.59		$	34.16		$	27.25		$	22.80		$	24.59		$	23.06
Proved reserves:
Natural gas (MMcf)		489,100			453,200			411,700			372,500			324,100			309,800
Oil (MBbls)		21,200			17,100			18,900			17,500			17,500			15,100
Construction Materials and Mining
Construction materials (000's):
Aggregates (tons sold)		47,204			43,444			38,438			35,078			27,565			18,315
Asphalt (tons sold)		9,142			8,643			7,275			7,272			6,228			3,310
Ready-mixed concrete (cubic yards sold)		4,448			4,292			3,484			2,902			2,542			1,696
Recoverable aggregate reserves (tons)		1,273,696			1,257,498			1,181,413			1,110,020			1,065,330			894,500
Coal (000's):
Sales (tons)		---*			---*			---*			---*			1,171*			3,111
Lignite deposits (tons)		11,400*			11,400*			26,910*			37,761*			56,012*			145,643
Independent Power Production**
Net generation capacity - kW		279,600			279,600			279,600			213,000			---			---
Electricity produced and sold (thousand kWh)		254,618			204,425			270,044			15,804			---			---

_____________________________________________

* Coal operations were sold effective April 30, 2001.

** Excludes equity method investments.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

The Company’s strategy is to apply its expertise in energy and transportation infrastructure industries to increase market share, increase profitability and enhance shareholder value through organic growth as well as a continued disciplined approach to the acquisition of well-managed companies and properties; the creation and enhancement of meaningful synergies and elimination of system-wide cost redundancies through increased focus on integration of operations and standardization and consolidation of various support services and functions across companies within the organization; and the development of projects that are accretive to earnings and returns on invested capital.

The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper facilities and the issuance from time to time of debt securities and the Company’s equity securities. The Company’s net capital expenditures for 2005 were $730.4 million. Net capital expenditures are comprised of (A) capital expenditures plus (B) acquisitions (including the issuance of the Company’s equity securities, less cash acquired) less (C) net proceeds from the sale or disposition of property. Net capital expenditures are estimated to be approximately $502.3 million for 2006.

The key strategies for each of the Company’s business segments, and certain related business challenges, are summarized below.

Key Strategies and Challenges

Electric and Natural Gas Distribution

Strategy Provide competitively priced energy to customers while working with them to ensure efficient usage. Both the electric and natural gas distribution segments continually seek opportunities for growth and expansion of their customer base through extensions of existing operations and through selected acquisitions of companies and properties at prices that will provide an opportunity for the Company to earn a competitive return on investment. The natural gas distribution segment also continues to pursue growth by expanding its level of energy-related services.

Challenges Both segments are subject to extensive regulation in the state jurisdictions where they conduct operations with respect to costs and permitted returns on investment as well as subject to certain operational regulations at the federal level. The ability of these segments to grow through acquisitions is subject to significant competition from other energy providers. In addition, as to the electric business, the ability of this segment to grow its service territory and customer base is affected by significant competition from other energy providers, including rural electric cooperatives.

Construction Services

Strategy Provide a competitive return on investment while operating in a competitive industry by: building new and strengthening existing customer relationships; effectively controlling costs including taking advantage of synergies; recruiting, developing and retaining talented employees; focusing business development efforts on project areas that will permit higher margins; and properly managing risk. This segment continuously seeks opportunities to expand through strategic acquisitions.

Challenges This segment operates in highly competitive markets, with many jobs subject to competitive bidding. Maintenance of effective cost controls and retention of key personnel are ongoing challenges.

Pipeline and Energy Services

Strategy Leverage the segment’s existing expertise in energy infrastructure, services and technologies to increase market share and profitability through optimization of existing operations, internal growth, and acquisitions of energy-related assets and companies. Incremental and new growth opportunities include: access to new sources of natural gas for storage, gathering and transportation services; expansion of existing gathering and transmission facilities; incremental expansion of the capacity of the Grasslands Pipeline to allow customers access to more liquid and potentially higher price markets; and pursuit of new markets for the segment’s locating and tracking technology business.

Challenges Energy price volatility; natural gas basis differentials; regulatory requirements; recruitment and retention of a skilled and reliable workforce; increased competition from other natural gas pipeline and gathering companies; and establishing and enhancing customer relationships at the location and tracking technology business.

Natural Gas and Oil Production

Strategy Apply new technology and leverage existing exploration and production expertise, with a focus on operated properties, to increase production and reserves from existing leaseholds, and to seek additional reserves and production opportunities in new areas to diversify the segment’s asset base. By optimizing existing operations and taking advantage of new and incremental growth opportunities, this segment’s goal is to increase both production and reserves over the long term so as to generate competitive returns on investment.

Challenges Fluctuations in natural gas and oil prices; ongoing environmental litigation and administrative proceedings; timely receipt of necessary permits and approvals; recruitment and retention of a skilled and reliable workforce; and increased competition from many of the larger natural gas and oil companies.

Construction Materials and Mining

Strategy Focus on high growth regional markets located near major transportation corridors and metropolitan areas; achieve economic synergies and enhance profitability through vertical integration of the segment’s operations; and continue growth through acquisitions. Vertical integration allows the segment to manage operations from aggregate mining to final lay-down of concrete and asphalt, with control of and access to adequate quantities of permitted aggregate reserves being significant. The segment’s key operating focus is on increasing margins and profitability through continuous implementation of a variety of improvement programs and operational synergies to generate targeted cost savings.

Challenges Price volatility with respect to, and availability of, raw materials such as steel and cement; petroleum price volatility; recruitment and retention of a skilled and reliable workforce; and increased competition from national and international construction materials companies. In particular, increases in energy prices can affect the profitability of construction jobs. The segment’s strategy is to mitigate this risk through centralized purchasing and negotiation of contract price escalation provisions. Similarly, the segment seeks to minimize its exposure to regional shortages of raw materials through utilization of national purchasing accounts.

Independent Power Production

Strategy Achieve growth through the acquisition, construction and operation of domestic nonregulated electric generation facilities and through international investments in the energy and natural resources sectors. The segment continues to seek projects with mid- to long-term agreements with financially stable customers, while maintaining diversity in customers, geographic markets and fuel source.

Challenges Overall business challenges for this segment include: the risks and uncertainties associated with the ongoing construction, startup and operation of power plant facilities; changes in energy market pricing; increased competition from other independent power producers; and fluctuations in the value of foreign currency and political risk in the countries where this segment does business.

For further information on the risks and challenges the Company faces as it pursues its growth strategies and other factors that should be considered for a better understanding of the Company’s financial condition, see Item 1A - Risk Factors. For further information on each segment’s key growth strategies, projections and certain assumptions, see Prospective Information.

For information pertinent to various commitments and contingencies, see Item 3 - Legal Proceedings and Item 8 - Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements.

Earnings Overview

The following table summarizes the contribution to consolidated earnings by each of the Company's businesses.

Years ended December 31,	2005			2004			2003
	(Dollars in millions, where applicable)
Electric	$	13.9		$	12.8		$	16.9
Natural gas distribution		3.5			2.2			3.9
Construction services		14.6			(5.6	)		6.2
Pipeline and energy services		22.1			8.9			18.2
Natural gas and oil production		141.6			110.8			63.0
Construction materials and mining		55.1			50.7			54.4
Independent power production		22.9			26.3			11.4
Other		.7			.3			.6
Earnings on common stock	$	274.4		$	206.4		$	174.6
Earnings per common share - basic	$	2.31		$	1.77		$	1.57
Earnings per common share - diluted	$	2.29		$	1.76		$	1.55
Return on average common equity		15.7	%		13.2	%		13.0	%

2005 compared to 2004 Consolidated earnings for 2005 increased $68.0 million from the comparable period largely due to:

·	Higher average realized natural gas prices of 30 percent and higher average realized oil prices of 25 percent at the natural gas and oil production business

·	Increased outside and inside electrical workloads and margins, as well as earnings from acquisitions made in the second quarter of 2005 at the construction services business

The benefit from the resolution of a rate proceeding of $5.0 million (after tax), which included a reduction to depreciation, depletion and amortization expense; and the absence in 2005 of the 2004 $4.0 million (before and after tax) noncash goodwill impairment relating to the Company’s cable and pipeline magnetization and location business, as well as the 2004 $1.3 million (after tax) adjustment reflecting the reduction in value of certain gathering facilities in the Gulf Coast region

Partially offsetting the increase in earnings was the absence in 2005 of the favorable resolution of federal and related state income tax matters realized in 2004, which resulted in a benefit of $8.3 million (after tax), including interest.

2004 compared to 2003 Consolidated earnings for 2004 increased $31.8 million from the comparable prior period. The earnings increase was largely the result of:

Higher average realized natural gas prices of 20 percent and higher average realized oil prices of 25 percent at the natural gas and oil production business

Increased natural gas production of 9 percent at the natural gas and oil production business

Higher net income of $14.8 million from the Company’s share of its equity method investment in Brazil

Favorable resolution of federal and related state income tax matters of $8.3 million (after tax), including interest

The absence in 2004 of a noncash transition charge in 2003 of $7.6 million (after tax), reflecting the cumulative effect of an accounting change, as discussed in Item 8 - Financial Statements and Supplementary Data - Notes 1 and 8

Partially offsetting the increase were:

Higher operation and maintenance expense including payroll, severance-related expenses, pension costs, higher fuel costs of which a significant portion was not recovered through higher prices at the construction materials and mining business, as well as costs associated with adverse weather at the Texas construction materials and mining business

Lower inside electrical margins at the construction services business, including the effect of losses on a few large jobs of $5.8 million (after tax)

A $4.0 million (before and after tax) noncash goodwill impairment relating to the Company’s cable and pipeline magnetization and location business, as well as a $1.3 million (after tax) adjustment reflecting the reduction in value of certain gathering facilities in the Gulf Coast region

FINANCIAL AND OPERATING DATA

Below are key financial and operating data for each of the Company's businesses.

Electric

Years ended December 31,	2005		2004		2003
	(Dollars in millions, where applicable)
Operating revenues	$	181.2	$	178.8	$	178.6
Operating expenses:
Fuel and purchased power		63.6		64.6		62.0
Operation and maintenance		59.5		59.0		52.9
Depreciation, depletion and amortization		20.8		20.2		20.2
Taxes, other than income		8.3		8.2		7.7
		152.2		152.0		142.8
Operating income		29.0		26.8		35.8
Earnings	$	13.9	$	12.8	$	16.9
Retail sales (million kWh)		2,413.7		2,303.5		2,359.9
Sales for resale (million kWh)		615.2		821.5		841.6
Average cost of fuel and purchased
power per kWh	$	.020	$	.019	$	.019

2005 compared to 2004 Electric earnings increased $1.1 million (9 percent) compared to the prior year due to:

·	Higher retail sales margins, largely due to 5 percent higher volumes, primarily residential, commercial and industrial, partially offset by increased fuel and purchased power costs

·	Higher sales for resale margins, primarily the result of higher average realized prices of 22 percent and lower fuel and purchased power-related costs, offset in part by decreased sales for resale volumes of 25 percent

·	Lower net interest expense of $900,000 (after tax)

Partially offsetting the increase in earnings was the absence in 2005 of the favorable resolution of federal and related state income tax matters realized in 2004 of $1.7 million (after tax), including interest.

2004 compared to 2003 Electric earnings decreased $4.1 million (25 percent) compared to the prior year, largely as a result of the following:

An increase in operation and maintenance expense of $3.7 million (after tax) due primarily to increased payroll, severance-related and pension expenses

Lower retail sales margins largely the result of decreased retail sales volumes of 2.4 percent, primarily the result of lower residential sales volumes due to cooler summer weather

Partially offsetting the decrease in earnings was a favorable resolution of federal and related state income tax matters of $1.7 million (after tax), including interest.

Natural Gas Distribution

Years ended December 31,

2005

2004

2003

(Dollars in millions, where applicable)

Operating revenues:
Sales	$	379.2		$	311.5		$	270.2
Transportation and other		5.0			4.6			4.4
		384.2			316.1			274.6
Operating expenses:
Purchased natural gas sold		315.4			251.1			211.1
Operation and maintenance		46.0			48.3			41.8
Depreciation, depletion and amortization		9.6			9.4			10.0
Taxes, other than income		5.8			5.5			5.2
		376.8			314.3			268.1
Operating income		7.4			1.8			6.5
Earnings	$	3.5		$	2.2		$	3.9
Volumes (MMdk):
Sales		36.2			36.6			38.6
Transportation		14.6			13.9			13.9
Total throughput		50.8			50.5			52.5
Degree days (% of normal)*		90.9	%		90.7	%		97.3	%
Average cost of natural gas,
including transportation, per dk	$	8.71		$	6.86		$	5.47
* Degree days are a measure of the daily temperature-related demand for energy for heating.

2005 compared to 2004 The natural gas distribution business experienced an increase in earnings of $1.3 million (61 percent) compared to the prior year due to:

·	Higher average realized rates of $2.0 million (after tax), largely the result of rate increases approved by various state public service commissions

·	Decreased operation and maintenance expenses, largely payroll-related costs

The increase was partially offset by the absence in 2005 of the favorable resolution of federal and related state income tax matters realized in 2004 of $3.0 million (after tax), including interest.

The pass-through of higher natural gas prices is reflected in the increase in both sales revenues and purchased natural gas sold.

2004 compared to 2003 The natural gas distribution business experienced a decrease in earnings of $1.7 million (44 percent) compared to the prior year. The earnings decrease largely resulted from:

Higher payroll, severance-related expenses, pension and other operational expenses of $5.2 million (after tax)

Decreased retail sales volumes of 5.1 percent, primarily lower residential and commercial sales volumes as a result of 6 percent warmer weather compared to last year

Partially offsetting the decrease in earnings were:

A favorable resolution of federal and related state income tax matters of $3.0 million (after tax), including interest

Higher retail sales prices, the result of rate increases effective in South Dakota, North Dakota and Minnesota

The pass-through of higher natural gas prices is reflected in the increase in both sales revenues and purchased natural gas sold.

Construction Services

Years ended December 31,

2005

2004

2003

(Dollars in millions)

Operating revenues	$687.1		$426.8			$434.2
Operating expenses:
Operation and maintenance		625.1		405.6			395.9
Depreciation, depletion and amortization		13.4		11.1			10.3
Taxes, other than income		20.4		15.8			15.1
		658.9		432.5			421.3
Operating income (loss)		28.2		(5.7	)		12.9
Earnings (loss)	$	14.6	$	(5.6	)	$	6.2

2005 compared to 2004 Construction services realized $14.6 million in earnings compared to a $5.6 million loss for the prior year. The $20.2 million increase in earnings is due to:

·	Higher outside and inside electrical workloads and margins of $12.8 million (after tax)

·	Earnings from businesses acquired during the second quarter of 2005, which contributed approximately 19 percent of the earnings increase

·	Higher equipment sales and rentals

·	Lower general and administrative expenses of $1.4 million (after tax), largely lower severance-related expenses

2004 compared to 2003 Construction services experienced a $5.6 million loss compared to $6.2 million in earnings for the prior year. The earnings decrease was attributable to:

Decreased inside electrical margins, including the effect of losses on a few large jobs of $5.8 million (after tax)

Increased severance and other general and administrative expenses of $3.6 million (after tax), including higher consulting and legal fees as well as other outside service costs

The decrease in earnings was partially offset by increased line construction margins.

Pipeline and Energy Services

Years ended December 31,	2005		2004		2003
	(Dollars in millions)
Operating revenues:
Pipeline	$	85.5	$	87.2	$	97.2
Energy services		394.8		270.0		155.0
		480.3		357.2		252.2
Operating expenses:
Purchased natural gas sold		363.7		249.8		149.5
Operation and maintenance		53.5		51.1		46.6
Depreciation, depletion and amortization		12.8		17.8		15.0
Taxes, other than income		7.9		7.7		5.9
Asset impairments		---		6.1		---
		437.9		332.5		217.0
Operating income		42.4		24.7		35.2
Earnings	$	22.1	$	8.9	$	18.2
Transportation volumes (MMdk):
Montana-Dakota		31.4		32.5		34.1
Other		73.5		81.7		56.1
		104.9		114.2		90.2
Gathering volumes (MMdk)		82.1		80.5		75.9

2005 compared to 2004 Pipeline and energy services earnings increased $13.2 million (147 percent) due largely to:

·	The benefit from the resolution of a rate proceeding of $5.0 million (after tax), as previously discussed. For further information see Item 8 - Financial Statements and Supplementary Data - Note 17

·	The absence in 2005 of the 2004 $4.0 million (before and after tax) noncash goodwill impairment and the 2004 $1.3 million (after tax) asset valuation adjustment, as previously discussed

·	Higher gathering rates of $4.4 million (after tax)

·	Lower net interest expense of $700,000 (after tax)

Partially offsetting the increase in earnings were:

·	The absence in 2005 of the favorable resolution of federal and related state income tax matters realized in 2004 of $1.6 million (after tax), including interest

·	Lower transportation and storage rates in 2005 of $1.5 million (after tax), largely the result of a FERC rate order received in July 2003 and a rehearing order received in May 2004, which resulted in lower rates effective July 1, 2004

The increase in energy services revenues and the related increase in purchased natural gas sold includes the effect of higher natural gas prices and volumes since the comparable prior period.

2004 compared to 2003 Earnings at the pipeline and energy services business decreased $9.3 million (51 percent) due largely to:

A $4.0 million (before and after tax) noncash goodwill impairment and a $1.3 million (after tax) asset valuation adjustment, as previously discussed

Increased operating costs of $5.3 million (after tax) including costs associated with the 2003 expansion of pipeline and gathering operations, as well as higher payroll-related costs

Higher financing-related costs of $2.2 million (after tax)

Lower average rates of $1.5 million (after tax), due in part to the estimated effects of a FERC rate order received in July 2003 and rehearing order received in May 2004, which resulted in lower rates effective July 1, 2004

Partially offsetting the decrease in earnings were:

Increased natural gas transportation volumes of $3.5 million (after tax), including:

Higher volumes transported on the Grasslands Pipeline (which began providing natural gas transmission service late in 2003)

Higher natural gas volumes transported into storage, which were largely commodity price related

A favorable resolution of federal and related state income tax matters of $1.6 million (after tax), including interest

The increase in energy services revenues and the related increase in purchased natural gas sold includes the effect of higher natural gas prices and volumes since the comparable prior period.

Natural Gas and Oil Production

Years ended December 31,	2005		2004		2003
	(Dollars in millions, where applicable)
Operating revenues:
Natural gas	$	362.5	$	280.4	$	213.5
Oil		72.7		59.7		50.6
Other		4.2		2.8		.2
		439.4		342.9		264.3
Operating expenses:
Purchased natural gas sold		4.3		2.7		.1
Operation and maintenance:
Lease operating costs		39.2		33.0		31.6
Gathering and transportation		14.1		11.6		14.7
Other		31.2		23.1		17.2
Depreciation, depletion and amortization		84.8		70.8		61.0
Taxes, other than income:
Production and property taxes		34.8		22.6		21.0
Other		.6		.2		.4
		209.0		164.0		146.0
Operating income		230.4		178.9		118.3
Earnings	$	141.6	$	110.8	$	63.0
Production:
Natural gas (MMcf)		59,378		59,750		54,727
Oil (MBbls)		1,707		1,747		1,856
Average realized prices (including hedges):
Natural gas (per Mcf)	$	6.11	$	4.69	$	3.90
Oil (per barrel)	$	42.59	$	34.16	$	27.25
Average realized prices (excluding hedges):
Natural gas (per Mcf)	$	6.87	$	4.90	$	4.28
Oil (per barrel)	$	48.73	$	37.75	$	28.42
Production costs, including taxes, per net
equivalent Mcf:
Lease operating costs	$	.56	$	.47	$	.48
Gathering and transportation		.20		.17		.22
Production and property taxes		.50		.32		.32
	$	1.26	$	.96	$	1.02

2005 compared to 2004 The natural gas and oil production business experienced an increase in earnings of $30.8 million (28 percent) due to:

·	Higher average realized natural gas prices of 30 percent

·	Higher average realized oil prices of 25 percent

Partially offsetting the increase were:

·	Higher depreciation, depletion and amortization expense of $8.6 million (after tax) due to higher rates, largely the result of the South Texas acquisition in the second quarter of 2005

·	Higher lease operating costs of $5.4 million (after tax), including costs related to the South Texas acquisition, and increased general and administrative expenses of $5.3 million (after tax), including payroll-related costs

·	A slight decrease in natural gas and oil production volumes as a result of the effects of hurricanes and normal production declines. Largely offsetting these declines were increases in production from other existing properties due to drilling activity and the South Texas acquisition

2004 compared to 2003 Natural gas and oil production earnings increased $47.8 million (76 percent) due to:

Higher average realized natural gas prices of 20 percent due in part to the Company’s ability to access higher and more stable-priced markets for much of its operated natural gas production through the Grasslands Pipeline

Higher natural gas production of 9 percent, largely the result of drilling activity

The absence in 2004 of a $12.7 million ($7.7 million after tax) noncash transition charge in 2003, reflecting the cumulative effect of an accounting change, as previously discussed

Higher average realized oil prices of 25 percent

Partially offsetting the increase in earnings were:

Higher depreciation, depletion and amortization expense of $6.0 million (after tax) due to higher rates and higher natural gas production volumes

Higher general and administrative costs of $3.5 million (after tax) due primarily to increased payroll-related expenses and outside services

Construction Materials and Mining

Years ended December 31,	2005		2004		2003
	(Dollars in millions)
Operating revenues	$	1,604.6	$	1,322.2	$	1,104.4
Operating expenses:
Operation and maintenance		1,381.9		1,132.3		924.2
Depreciation, depletion and amortization		78.0		69.6		63.6
Taxes, other than income		39.4		34.3		25.0
		1,499.3		1,236.2		1,012.8
Operating income		105.3		86.0		91.6
Earnings	$	55.1	$	50.7	$	54.4
Sales (000's):
Aggregates (tons)		47,204		43,444		38,438
Asphalt (tons)		9,142		8,643		7,275
Ready-mixed concrete (cubic yards)		4,448		4,292		3,484

2005 compared to 2004 Earnings at the construction materials and mining business increased $4.4 million (9 percent) due to:

·	Increased ready-mixed concrete margins of $4.7 million (after tax), largely in the Pacific and Northwest regions

·	Earnings from companies acquired since the comparable prior period, which contributed less than 5 percent of earnings

·	Higher cement volumes

Partially offsetting the increase were:

·	Higher depreciation, depletion and amortization expense of $3.2 million (after tax), due in part to higher property, plant and equipment balances from existing operations

·	The absence in 2005 of the 2004 favorable resolution of federal and related tax matters of $1.2 million (after tax), including interest

Construction and aggregate margin increases in most regions were largely offset by significantly lower margins in Texas, which included the effects of higher fuel, maintenance and repair costs.

2004 compared to 2003 Construction materials and mining earnings decreased $3.7 million (7 percent) due to:

Lower aggregate and construction margins of $10.5 million (after tax) from existing operations largely as a result of:

- The absence of certain large projects reflected in 2003 results

Wet weather which severely impacted operations in Texas

Increased fuel costs of which a significant portion was not recovered through higher prices

Higher general and administrative expenses of $5.3 million (after tax), including payroll-related costs, insurance and professional services

Partially offsetting the decrease in earnings were:

Increased ready-mixed concrete margins of $2.7 million (after tax), largely as a result of higher sales volumes from existing operations

Earnings from companies acquired since the comparable prior period contributed approximately 5 percent of earnings

Independent Power Production

Years ended December 31,

2005

2004

2003

(Dollars in millions)

Operating revenues	$	48.5	$	43.1	$	32.3
Operating expenses:
Operation and maintenance		32.0		23.0		13.8
Depreciation, depletion and amortization		9.0		9.6		7.9
Taxes, other than income		2.6		2.4		---
		43.6		35.0		21.7
Operating income		4.9		8.1		10.6
Earnings	$	22.9	$	26.3	$	11.4
Net generation capacity - kW*		279,600		279,600		279,600
Electricity produced and sold (thousand kWh)*		254,618		204,425		270,044
* Excludes equity method investments.

2005 compared to 2004 Independent power production experienced a decrease in earnings of $3.4 million (13 percent), largely due to:

The absence in 2005 of 2004 operating income from the Termoceara Generating Facility, benefits received in 2004 related to foreign currency gains and the effects of the embedded derivative in the Brazilian electric power sales contract were partially offset by a gain from the sale of the company’s equity interest in the Termoceara Generating Facility in June 2005

·	Higher general and administrative expense of $1.7 million (after tax), largely consulting and payroll-related costs

·	Lower earnings of $900,000 related to a domestic electric generating facility, largely lower capacity revenues and higher gas transportation fees

Partially offsetting the earnings decrease were:

·	Earnings from equity method investments acquired since the comparable prior period, which contributed less than 5 percent of earnings

·	Lower interest expense of $1.2 million (after tax)

·	Increased earnings from wind generation of $1.2 million, largely due to benefits related to higher production

For additional information regarding equity method investments, see Item 8 - Financial Statements and Supplementary Data - Note 2.

2004 compared to 2003 Earnings for the independent power production business were $26.3 million compared to $11.4 million in 2003. This increase is largely due to:

Higher net income of $14.8 million from the Company’s share of its equity method investment in Brazil due primarily to:

Changes in value of the embedded derivative in the Brazilian electric power sales contract, net of lower operating margins resulting from the contract annual revenue reset provision, as well as other foreign currency changes, totaling $8.5 million (after tax)

Lower financing costs of $4.8 million (after tax), largely the result of obtaining low-cost, long-term financing for the operation in mid-2003

Earnings from acquisitions and equity method investments acquired since the comparable prior period contributed approximately 7 percent of earnings

For additional information regarding equity method investments, see Item 8 - Financial Statements and Supplementary Data - Note 2.

Other and Intersegment Transactions

Amounts presented in the preceding tables will not agree with the Consolidated Statements of Income due to the Company’s other operations and the elimination of intersegment transactions. The amounts relating to these items are as follows:

Years ended December 31,	2005		2004		2003
	(In millions)
Other:
Operating revenues	$	6.0	$	4.4	$	2.7
Operation and maintenance		5.1		4.0		1.2
Depreciation, depletion and amortization		.3		.3		.3
Taxes, other than income		.2		---		---
Intersegment transactions:
Operating revenues	$	375.9	$	272.2	$	191.1
Purchased natural gas sold		354.2		253.7		176.5
Operation and maintenance		21.7		18.5		14.6

For further information on intersegment eliminations, see Item 8 - Financial Statements and Supplementary Data - Note 13.

PROSPECTIVE INFORMATION

The following information highlights the key growth strategies, projections and certain assumptions for the Company and its subsidiaries 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. Please refer to assumptions contained in this section as well as the various important factors listed in Item 1A - Risk Factors. Changes in such assumptions and factors could cause actual future results to differ materially from the Company’s targeted growth, revenue and earnings projections.

MDU Resources Group, Inc.

·	Earnings per common share for 2006, diluted, are projected in the range of $2.00 to $2.20.

·	The Company expects the percentage of 2006 earnings per common share, diluted, by quarter to be in the following approximate ranges:

-	First quarter - 10 percent to 15 percent

-	Second quarter - 20 percent to 25 percent

-	Third quarter - 35 percent to 40 percent

-	Fourth quarter - 25 percent to 30 percent

·	The Company’s long-term compound annual growth goals on earnings per share from operations are in the range of 7 percent to 10 percent.

Electric

This segment is involved in the review of potential power projects to replace capacity associated with expiring purchased power contracts and to provide for future growth. The projects under consideration include a proposed 600-MW coal-fired facility to be located in northeastern South Dakota or construction of a 175-MW lignite coal-fired facility (Vision 21) to be located in southwestern North Dakota. A decision on which of these facilities Montana-Dakota will participate in is expected in early 2007. In addition, for its power generation capacity needs beyond 2011, this segment is evaluating additional alternatives, including the potential of participating in a separate coal-fired facility to be located in the upper Midwest. This segment also is considering participation in a base-load sub-bituminous electric generating facility in Wyoming. The costs of building and/or acquiring the additional generating capacity needed by the utility are expected to be recovered in rates.

Montana-Dakota has obtained and holds, or is in the process of renewing, valid and existing franchises authorizing it to conduct its electric operations in all of the municipalities it serves where such franchises are required. Montana-Dakota intends to protect its service area and seek renewal of all expiring franchises.

Natural gas distribution

In September 2004, a natural gas rate case was filed with the MPUC requesting an increase of $1.4 million annually, or 4.0 percent. An interim increase of $1.4 million annually was approved by the MPUC effective January 10, 2005, subject to refund. A final order on this case is expected in early 2006.

Montana-Dakota and Great Plains have obtained and hold, or are in the process of renewing, valid and existing franchises authorizing them to conduct their natural gas operations in all of the municipalities they serve where such franchises are required. Montana-Dakota and Great Plains intend to protect their service areas and seek renewal of all expiring franchises.

Construction services

·	Revenues in 2006 are expected to be higher than 2005 record levels.

·	The Company anticipates margins to strengthen in 2006 as compared to 2005 levels.

Pipeline and energy services

·	In 2006, total gathering and transportation throughput is expected to increase approximately 5 percent over 2005 levels.

·	Firm capacity for the Grasslands Pipeline is 90,000 Mcf per day with expansion possible to 200,000 Mcf per day. Based on anticipated demand, incremental expansions are forecasted over the next few years beginning as early as 2007.

Natural gas and oil production

The Company’s long-term compound annual growth goals for production are in the range of 7 percent to 10 percent. In 2006, the Company expects a combined natural gas and oil production increase to be at least in that range, with the possibility of exceeding the upper end of the range. In late January 2006, the net combined natural gas and oil production was approximately 200,000 Mcf equivalent to 210,000 Mcf equivalent per day.

·	The Company is expecting to drill more than 300 wells in 2006.

Estimates of natural gas prices in the Rocky Mountain region for February through December 2006 reflected in the Company’s 2006 earnings guidance are in the range of $5.50 to $6.00 per Mcf. The Company’s estimates for natural gas prices on the NYMEX for February through December 2006, reflected in the Company’s 2006 earnings guidance, are in the range of $6.75 to $7.25 per Mcf. During 2005, more than three-fourths of this segment’s natural gas production was priced using Rocky Mountain or other non-NYMEX prices.

·	Estimates of NYMEX crude oil prices for February through December 2006, reflected in the Company’s 2006 earnings guidance, are projected in the range of $50 to $55 per barrel.

For 2006, the Company has hedged approximately 30 percent to 35 percent of its estimated natural gas production and approximately 20 percent to 25 percent of its estimated oil production. For 2007, the Company has hedged approximately 5 percent of its estimated natural gas production. The hedges that are in place as of January 26, 2006, for 2006 and 2007 are summarized below:

Commodity	Index*	Period Outstanding	Forward Notional Volume (MMBtu)/(Bbl)	Price Swap or Costless Collar Floor-Ceiling (Per MMBtu/Bbl)
Natural Gas	Ventura	1/06 - 12/06	1,825,000	$6.00-$7.60
Natural Gas	Ventura	1/06 - 12/06	3,650,000	$6.655
Natural Gas	CIG	1/06 - 3/06	900,000	$7.16
Natural Gas	CIG	1/06 - 3/06	810,000	$7.05
Natural Gas	Ventura	1/06 - 12/06	1,825,000	$6.75-$7.71
Natural Gas	Ventura	1/06 - 12/06	1,825,000	$6.75-$7.77
Natural Gas	Ventura	1/06 - 12/06	1,825,000	$7.00-$8.85
Natural Gas	NYMEX	1/06 - 12/06	1,825,000	$7.75-$8.50
Natural Gas	Ventura	1/06 - 12/06	1,825,000	$7.76
Natural Gas	CIG	4/06 - 12/06	1,375,000	$6.50-$6.98
Natural Gas	CIG	4/06 - 12/06	1,375,000	$7.00-$8.87
Natural Gas	Ventura	1/06 - 12/06	912,500	$8.50-$10.00
Natural Gas	Ventura	1/06 - 12/06	912,500	$8.50-$10.15
Natural Gas	Ventura	1/06 - 3/06	540,000	$12.00-$17.25
Natural Gas	Ventura	4/06 - 10/06	1,070,000	$9.25-$12.88
Natural Gas	Ventura	4/06 - 10/06	1,070,000	$9.25-$12.80
Natural Gas	Ventura	1/07 - 12/07	1,825,000	$8.00-$11.91
Natural Gas	Ventura	1/07 - 12/07	912,500	$8.00-$11.80
Natural Gas	Ventura	1/07 - 12/07	912,500	$8.00-$11.75
Crude Oil	NYMEX	1/06 - 12/06	182,500	$43.00-$54.15
Crude Oil	NYMEX	1/06 - 12/06	146,000	$60.00-$69.20
Crude Oil	NYMEX	2/06 - 12/06	83,500	$60.00-$76.80
* Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system.

Construction materials and mining

·	The Company anticipates margins to improve significantly in 2006 compared to 2005 levels largely because of higher expected aggregate and construction margins in Texas.

·	Ready-mixed concrete volumes for 2006 are expected to be slightly higher than levels achieved in 2005; aggregate and asphalt volumes are expected to be comparable to 2005 levels.

Independent power production

This segment is expected to experience minimal earnings for 2006 because of the sale of the Company’s equity investment in the Termoceara Generating Facility in June 2005, significantly higher interest expense related to the construction of the Hardin Generating Facility and lower revenues because of the bridge contract renewal at the Brush Generating Facility.

·	This segment is focused on redeploying the funds from the sale of the Termoceara Generating Facility into strategic assets using its disciplined approach for acquisitions.

NEW ACCOUNTING STANDARDS

SAB No. 106

In September 2004, the SEC issued SAB No. 106, which is an interpretation regarding the application of SFAS No. 143 by oil and gas producing companies following the full-cost accounting method. SAB No. 106 was effective for the Company as of January 1, 2005. The adoption of SAB No. 106 did not have a material effect on the Company's financial position or results of operations.

SFAS No. 123 (revised)

In December 2004, the FASB issued SFAS No. 123 (revised). This accounting standard revises SFAS No. 123 and requires entities to recognize compensation expense in an amount equal to the grant-date fair value of share-based payments granted to employees. SFAS No. 123 (revised) requires a company to record compensation expense for all awards granted after the date of adoption of SFAS No. 123 (revised) and for the unvested portion of previously granted awards that remain outstanding at the date of adoption. SFAS No. 123 (revised) is effective for the Company on January 1, 2006. The Company estimates the adoption of SFAS No. 123 (revised) will result in less than $300,000 (after tax) in additional stock-based compensation expense for the year ended December 31, 2006.

FIN 47

In March 2005, the FASB issued FIN 47. FIN 47 addresses the diverse accounting practices that developed with respect to the timing of liability recognition for legal obligations associated with the retirement of a tangible long-lived asset when the timing and/or method of settlement of the obligation are conditional on a future event. FIN 47 is effective for the Company at the end of the fiscal year ending December 31, 2005. The adoption of FIN 47 did not have a material effect on the Company's financial position or results of operations.

EITF No. 04-6

In March 2005, the FASB ratified EITF No. 04-6. EITF No. 04-6 requires that post-production stripping costs be treated as a variable inventory production cost. EITF No. 04-6 is effective for the Company on January 1, 2006. The adoption of EITF No. 04-6 is not expected to have a material effect on the Company’s financial position or results of operations.

For further information on SAB No. 106, SFAS No. 123 (revised), FIN 47 and EITF No. 04-6, 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 as well as 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. 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 and intangibles, excluding natural gas and oil properties, whenever events or changes in circumstances indicate that such carrying values may not be recoverable and annually for goodwill. 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 when the estimates are made.

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 SEC, plus the cost 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 noncash 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 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

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 liability assumptions and may from time to time change its liability 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. Inasmuch as contract prices are generally set before the work is performed, the estimates pertaining to every project could contain significant unknown risks such as volatile labor, material and fuel 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, materials and fuel, 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 when 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 and intangibles.

The fair value of owned recoverable aggregate reserve deposits is 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.

The fair value of leasehold rights 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 considerable degree 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.

Asset retirement obligations

Entities are required 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, special handling and disposal of hazardous materials at certain electric generating facilities, natural gas distribution and transmission facilities and buildings 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 likelihood 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 the range of time over which the Company may settle the obligation is unknown or cannot be estimated, 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 Company’s 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 when 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 Net income before depreciation, depletion and amortization is a significant contributor to cash flows from operating activities. The changes in cash flows from operating activities generally follow the results of operations as discussed in Financial and Operating Data and also are affected by changes in working capital. Cash flows provided by operating activities in 2005 increased $50.2 million from the comparable 2004 period, the result of:

·	Increased net income of $68.0 million, largely increased earnings at the natural gas and oil production, construction services and pipeline and energy services businesses (Net income in 2004 includes noncash asset impairments of $6.1 million.)

·	Higher depreciation, depletion and amortization expense of $19.9 million largely at the natural gas and oil production and construction materials and mining businesses, as previously discussed

·	Decreased earnings, net of distributions, from equity method investments of $7.9 million, primarily the result of the sale of the Termoceara Generating Facility

Partially offsetting the increase in cash flows from operating activities were:

·	Higher working capital requirements of $54.0 million due in part to:

-	Higher receivables, largely increased workloads and acquisition-related increases at the construction services business

-	Higher income tax payments due to lower tax depreciation and higher net income

Partially offset by higher accounts payable due to increased workloads and acquisition-related increases at the construction services business, higher natural gas costs at the natural gas distribution business and increased drilling costs due to increased drilling activity at the natural gas and oil production business

Cash flows provided by operating activities in 2004 increased $14.7 million from the comparable 2003 period, the result of:

·	An increase in net income of $31.7 million (Net income in 2004 includes noncash asset impairments of $6.1 million. Net income in 2003 includes the noncash cumulative effect of an accounting change of $7.6 million.)

Higher depreciation, depletion and amortization expense of $20.4 million largely due to higher rates and higher natural gas production volumes at the natural gas and oil production business and higher property, plant and equipment due to acquisitions at the construction materials and mining business

·	Changes in working capital of $19.1 million

Partially offsetting the increase in cash flows from operating activities were:

·	Decreased deferred income taxes of $31.4 million, which reflects the effects of higher depreciation, depletion and amortization expense, as previously discussed, as well as lower tax depreciation in 2004 on the Grasslands Pipeline

·	Increased earnings, net of distributions, from equity method investments of $18.2 million

Investing activities Cash flows used in investing activities in 2005 increased $257.3 million compared to the comparable 2004 period, the result of:

·	An increase in net capital expenditures of $329.6 million, due largely to acquisitions (including the acquisition of natural gas and oil production properties in southern Texas), the construction of the Hardin Generating Facility and higher ongoing capital expenditures

·	The absence in 2005 of the $22.0 million proceeds from notes receivable in 2004

Partially offsetting the increase in cash flows used in investing activities were:

·	Lower investments of $56.1 million, including the absence in 2005 of the 2004 investments in the Hartwell and Trinity Generating Facilities

·	Proceeds of $38.2 million from the sale of the Termoceara Generating Facility

Cash flows used in investing activities in 2004 decreased $34.4 million compared to the comparable 2003 period, the result of:

·	A decrease in net capital expenditures of $77.0 million

·	An increase in proceeds from notes receivable of $14.2 million

An increase in investments of $56.8 million, including equity method investments, partially offset the decrease in cash flows used in investing activities.

Financing activities Cash flows provided by financing activities in 2005 increased $202.2 million compared to the comparable 2004 period, primarily the result of an increase in the issuance of long-term debt of $338.5 million due in part to acquisitions and the construction of the Hardin Generating Facility.

The increase in cash flows from financing activities was partially offset by:

·	Increased repayment of long-term debt of $68.8 million, including the redemption of $20.9 million of Pollution Control Refunding Revenue bonds and certain scheduled debt repayments

·	A decrease in proceeds from the issuance of common stock of $61.0 million reflecting the absence in 2005 of the 2004 proceeds received from an underwritten public offering

Cash flows provided by financing activities in 2004 decreased $54.8 million compared to the comparable 2003 period, primarily the result of a decrease in proceeds from the issuance of long-term debt of $204.4 million.

Partially offsetting the decrease in cash provided by financing activities were:

·	A decrease in repayment of long-term debt of $67.7 million

·	An increase in proceeds from the issuance of common stock of $69.6 million, primarily due to net proceeds received from an underwritten public offering

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, 2005, certain Pension Plans’ accumulated benefit obligations exceeded these plans’ assets by approximately $12.3 million. Pretax pension expense reflected in the years ended December 31, 2005, 2004 and 2003, was $6.6 million, $4.1 million and $153,000, respectively. The Company’s pension expense is currently projected to be approximately $8.0 million to $9.0 million in 2006. A reduction in the Company’s assumed discount rate for Pension Plans along with lower than expected asset returns have combined to largely produce the increase in these costs. Funding for the Pension Plans is actuarially determined. The minimum required contributions for 2005, 2004 and 2003 were approximately $1.6 million, $1.2 million and $1.6 million, respectively. For further information on the Company’s Pension Plans, see Item 8 - Financial Statements and Supplementary Data - Note 15.

Capital expenditures

The Company's capital expenditures for 2003 through 2005 and as anticipated for 2006 through 2008 are summarized in the following table, which also includes the Company's capital needs for the retirement of maturing long-term debt.

	Actual									Estimated*
	2003			2004			2005			2006			2007			2008
							(In millions)
Capital expenditures:
Electric	$	28.5		$	18.8		$	27.0		$	57.5		$	68.3		$	123.2
Natural gas distribution		15.7			17.4			17.2			21.0			25.4			17.0
Construction services		7.8			8.5			50.9			33.9			17.5			12.0
Pipeline and energy services		93.0			38.3			36.4			39.8			36.4			30.9
Natural gas and oil production		101.7			111.5			329.8			220.0			215.5			211.8
Construction materials and mining		128.5			133.0			162.0			102.7			75.9			73.6
Independent power production		110.9			76.2			135.8			28.3			25.9			25.7
Other		1.9			4.2			11.9			2.0			1.7			1.4
		488.0			407.9			771.0			505.2			466.6			495.6
Net proceeds from sale or disposition of property		(14.4	)		(20.5	)		(40.6	)		(2.9	)		(3.4	)		(1.6	)
Net capital expenditures		473.6			387.4			730.4			502.3			463.2			494.0
Retirement of long-term debt		105.7			38.0			106.8			101.8			106.9			161.3
	$	579.3		$	425.4		$	837.2		$	604.1		$	570.1		$	655.3
* The estimated 2006 through 2008 capital expenditures reflected in the above table include 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 above estimates.

Capital expenditures for 2005, 2004 and 2003, in the preceding table include noncash transactions, including the issuance of the Company’s equity securities in connection with acquisitions. The noncash transactions were $46.5 million in 2005, $33.1 million in 2004 and $42.4 million in 2003.

In 2005, the Company acquired construction services businesses in Nevada, natural gas and oil production properties in southern Texas and construction materials and mining businesses in Idaho, Iowa and Oregon, none of which was material. The total purchase consideration for these businesses and properties and purchase price adjustments with respect to certain other acquisitions acquired prior to 2005, consisting of the Company's common stock and cash, was $245.2 million.

The 2005 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 2006 through 2008 include those for:

·	Potential future acquisitions

·	System upgrades

·	Routine replacements

·	Service extensions

·	Routine equipment maintenance and replacements

·	Buildings, land and building improvements

·	Pipeline and gathering projects

·	Further enhancement of natural gas and oil production and reserve growth

·	Power generation opportunities, including certain costs for additional electric generating capacity

·	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 2006 through 2008 will be met from various sources, including 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, 2005.

MDU Resources Group, Inc. The Company has a revolving credit agreement with various banks totaling $100 million (with provision for an increase, at the option of the Company on stated conditions, up to a maximum of $125 million). There were no amounts outstanding under the credit agreement at December 31, 2005. The credit agreement supports the Company’s $100 million (previously $75 million) commercial paper program. Under the Company’s commercial paper program, $60.0 million was outstanding at December 31, 2005. The commercial paper borrowings are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings (supported by the credit agreement, which expires in June 2010).

The Company’s objective 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 an 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, 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 $90,000 (after tax) based on December 31, 2005, variable rate borrowings.

Prior to the maturity of the credit agreement, the Company expects that it will negotiate the extension or replacement of this agreement. If the Company is unable to successfully negotiate an extension of, or replacement for, the credit agreement, or if the fees on this facility became too expensive, which the Company 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, including covenants not to permit, as of the end of any fiscal quarter, (A) the ratio of funded debt to total capitalization (determined on a consolidated basis) to be greater than 65 percent or (B) the ratio of funded debt to capitalization (determined with respect to the Company alone, excluding its subsidiaries) to be greater than 65 percent. Also included is a covenant that does not permit the ratio of the Company's earnings before interest, taxes, depreciation and amortization to interest expense (determined with respect to the Company alone, excluding its subsidiaries), for the 12-month period ended each fiscal quarter, to be less than 2.5 to 1. Other covenants include restrictions on the sale of certain assets and on the making of certain investments. The Company was in compliance with these covenants and met the required conditions at December 31, 2005. 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.

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 fund $1.43 of unfunded property or use $1.00 of refunded bonds for each dollar of indebtedness incurred under the Indenture and, in some cases, to certify to the trustee 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 tests, as of December 31, 2005, the Company could have issued approximately $364 million of additional first mortgage bonds.

The Company's coverage of fixed charges including preferred dividends was 6.1 times and 4.7 times for the 12 months ended December 31, 2005 and 2004, respectively. Additionally, the Company's first mortgage bond interest coverage was 10.2 times and 7.1 times for the 12 months ended December 31, 2005 and 2004, respectively. Common stockholders' equity as a percent of total capitalization (net of long-term debt due within one year) was 63 percent and 65 percent at December 31, 2005 and 2004, respectively.

The Company has repurchased, and may from time to time seek to repurchase, outstanding first mortgage bonds through open market purchases or privately negotiated transactions. The Company will evaluate any such transactions in light of then existing market conditions, taking into account its liquidity and prospects for future access to capital. As of February 14, 2006, the Company had $57.0 million of first mortgage bonds outstanding (and had repurchased $68.0 million of first mortgage bonds between January 1 and February 14, 2006). At such time as the aggregate principal amount of the Company’s outstanding first mortgage bonds, other than those held by the Indenture trustee, is $20 million or less, the Company would have the ability, subject to satisfying certain specified conditions, to require that any debt issued under its Indenture, dated as of December 15, 2003, as supplemented, from the Company to The Bank of New York, as trustee, become unsecured and rank equally with all of the Company’s other unsecured and unsubordinated debt (as of February 14, 2006, the only such debt outstanding under the Indenture was $30.0 million in aggregate principal amount of the Company’s 5.98% Senior Notes due in 2033).

Centennial Energy Holdings, Inc. Centennial has three revolving credit agreements with various banks and institutions totaling $441.4 million with certain provisions allowing for increased borrowings. These credit agreements support Centennial’s $350 million commercial paper program. There were no outstanding borrowings under the Centennial credit agreements at December 31, 2005. Under the Centennial commercial paper program, $200.0 million was outstanding at December 31, 2005. 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 (supported by Centennial credit agreements). One of these credit agreements is for $400 million, which includes a provision for an increase, at the option of Centennial on stated conditions, up to a maximum of $450 million and expires on August 26, 2010. Another agreement is for $21.4 million and expires on April 30, 2007. Pursuant to this credit agreement, on the last business day of April 2006, the line of credit will be reduced by $3.6 million. Centennial intends to negotiate the extension or replacement of these agreements prior to their maturities. The third agreement is an uncommitted line for $20 million, which was effective on January 27, 2006, and may be terminated by the bank at any time. As of December 31, 2005, $32.3 million of letters of credit were outstanding, as discussed in Item 8 - Financial Statements and Supplementary Data - Note 18, of which $14.9 million were outstanding under the above credit agreements that reduced amounts available under these agreements.

Centennial has an uncommitted long-term master shelf agreement that allows for borrowings of up to $450 million. Under the terms of the master shelf agreement, $447.5 million was outstanding at December 31, 2005. The ability to request additional borrowings under this master shelf agreement expires in April 2008. To meet potential future financing needs, Centennial may pursue other financing arrangements, including private and/or public financing.

Centennial’s objective 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 an 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, 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 $300,000 (after tax) based on December 31, 2005, variable rate borrowings. Based on Centennial’s overall interest rate exposure at December 31, 2005, 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 expects that it will negotiate the extension or replacement of these agreements, which 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, including covenants not to permit, as of the end of any fiscal quarter, the ratio of total debt to total capitalization to be greater than 65 percent (for the $400 million credit agreement) and 60 percent (for the $21.4 million credit agreement and the master shelf agreement). Also included is a covenant that does not permit the ratio of the Company's earnings before interest, taxes, depreciation and amortization to interest expense, for the 12-month period ended each fiscal quarter, to be less than 2.5 to 1 (for the $400 million credit agreement), 2.25 to 1 (for the $21.4 million credit agreement) and 1.75 to 1 (for the master shelf agreement). Other covenants include minimum consolidated net worth, limitation on priority debt and restrictions on the sale of certain assets and on the making of certain loans and investments. Centennial and such subsidiaries were in compliance with these covenants and met the required conditions at December 31, 2005. 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, 2005. The ability to request additional borrowings under this master shelf agreement expires on December 20, 2007.

In order to borrow under its uncommitted long-term master shelf agreement, Williston Basin must be in compliance with the applicable covenants and certain other conditions, including covenants not to permit, as of the end of any fiscal quarter, the ratio of total debt to total capitalization to be greater than 55 percent. Other covenants include limitation on priority debt and some restrictions on the sale of certain assets and the making of certain investments. Williston Basin was in compliance with these covenants and met the required conditions at December 31, 2005. 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

In connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly owned subsidiary of the Company has agreed to indemnify Petrobras for 49 percent of any losses that Petrobras may incur from certain contingent liabilities specified in the purchase agreement. Centennial has agreed to unconditionally guarantee payment of the indemnity obligations to Petrobras for periods ranging from approximately two to five and a half years from the date of sale. The guarantee was required by Petrobras as a condition to closing the sale of MPX.

As of December 31, 2005, Centennial was contingently liable for the performance of certain of its subsidiaries under approximately $454 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 is 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 7 and 18. At December 31, 2005, the Company’s commitments under these obligations were as follows:

	2006		2007		2008		2009		2010		Thereafter		Total
	(In millions)
Long-term debt	$	101.8	$	106.9	$	161.3	$	86.9	$	266.8	$	482.8	$	1,206.5
Estimated interest
payments*		66.1		56.6		50.4		43.2		36.0		115.8		368.1
Operating leases		13.2		8.6		6.5		4.2		2.8		24.1		59.4
Purchase
commitments		303.6		131.3		79.5		63.5		62.7		294.4		935.0
	$	484.7	$	303.4	$	297.7	$	197.8	$	368.3	$	917.1	$	2,569.0
*Estimated interest payments are calculated based on the applicable rates and payment dates.

In addition to the above obligations, the Company has certain purchase obligations for natural gas connected to its gathering system. These purchases and the resale of the natural gas are at market-based prices. These obligations continue as long as natural gas is produced. However, if the purchase and resale of natural gas becomes uneconomical, the purchase commitments can be canceled by the Company with 60 days notice. These purchase obligations are estimated at approximately $10 million annually.

EFFECTS OF INFLATION

Inflation did not have a significant effect on the Company's operations in 2005, 2004 or 2003.

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 that natural gas and oil price derivative instruments and interest rate derivative instruments not exceed a period of 24 months and foreign currency derivative instruments not exceed a 12-month period. 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 on 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; 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 would 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.

Commodity price risk

Fidelity 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 its 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.

The fair value of the hedging instruments must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or liability. Changes in the fair value attributable to the effective portion of hedging instruments, net of tax, are recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). At the date the natural gas or oil production quantities are settled, 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. Based on the recent rise in market prices of natural gas and oil, the fair value of the Company’s derivative liability has increased significantly since December 31, 2004. The proceeds the Company receives for its natural gas and oil production also are generally based on market prices.

The following table summarizes hedge agreements entered into by Fidelity as of December 31, 2005. These agreements call for Fidelity 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 2006	$	7.04		7,185		$	(18,303	)

		Weighted
		Average
		Floor/Ceiling		Notional
		Price		Amount
		(Per MBtu)		(In MMBtu’s	)		Fair Value
Natural gas collar agreements maturing in 2006	$	7.50/$9.20		16,380		$	(21,874	)

		Weighted
		Average
		Floor/Ceiling		Notional
		Price		Amount
		(Per barrel)		(In barrels	)		Fair Value
Oil collar agreements maturing in 2006	$	50.56/$60.84		329		$	(1,834	)

The following table summarizes hedge agreements entered into by Fidelity as of December 31, 2004. These agreements call for Fidelity 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 2005	$	5.39		8,020		$	(4,187	)

		Weighted
		Average
		Floor/Ceiling		Notional
		Price		Amount
		(Per MBtu)		(In MMBtu’s	)		Fair Value
Natural gas collar agreements maturing in 2005	$	5.42/$6.64		15,050		$	(168	)

		Weighted
		Average		Notional
		Fixed Price		Amount
		(Per barrel)		(In barrels	)		Fair Value
Oil swap agreement maturing in 2005	$	30.70		183		$	(2,138	)

		Weighted
		Average
		Floor/Ceiling		Notional
		Price		Amount
		(Per barrel)		(In barrels	)		Fair Value
Oil collar agreements maturing in 2005	$	37.79/$44.68		347		$	(608	)

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 also has 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, 2005.

																						Fair
	2006			2007			2008			2009			2010			Thereafter			Total			Value
	(Dollars in millions)
Long-term debt:
Fixed rate	$	101.8		$	106.9		$	161.3		$	86.9		$	6.8		$	482.8		$	946.5		$	960.1
Weighted average
interest rate		6.5	%		8.1	%		4.5	%		6.2	%		6.8	%		6.0	%		6.0	%		---
Variable rate		---			---			---			---		$	260.0			---		$	260.0		$	259.2
Weighted average
interest rate		---			---			---			---			4.3	%		---			4.3	%		---

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

The Company’s investment in the Termoceara Generating Facility was sold in June 2005 as discussed in Item 8 - Financial Statements and Supplementary Data - Note 2 and, as a result, the Company no longer has any material exposure to foreign currency exchange risk.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of MDU Resources Group, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. The Company’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.

Based on our evaluation under the framework in Internal Control-Integrated Framework, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2005.

Management’s assessment of the Company’s internal control over financial reporting as of December 31, 2005, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report.

/s/ Martin A. White	/s/ Vernon A. Raile
Martin A. White	Vernon A. Raile
Chairman of the Board	Executive Vice President and
and Chief Executive Officer	Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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. and subsidiaries (the “Company”) as of December 31, 2005 and 2004, 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, 2005. Our audits also included the financial statement schedule for each of the three years in the period ended December 31, 2005, listed in the Index at Item 15. These consolidated financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule for each of the three years in the period ended December 31, 2005, when considered in relation to the consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Notes 1 and 8 to the consolidated financial statements, effective January 1, 2003, and December 31, 2005, the Company changed its method of accounting for asset retirement obligations.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2006, expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 22, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF MDU RESOURCES GROUP, INC.:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that MDU Resources Group, Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule of the Company as of and for the year ended December 31, 2005, and our report dated February 22, 2006, expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ Deloitte & Touche LLP

DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 22, 2006

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME

Years ended December 31,	2005		2004		2003
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline
and energy services	$	953,307	$	776,836	$	641,062
Construction services, natural gas and oil production,
construction materials and mining, independent
power production and other		2,502,107		1,942,421		1,711,127
		3,455,414		2,719,257		2,352,189
Operating expenses:
Fuel and purchased power		63,591		64,618		62,037
Purchased natural gas sold		329,190		249,924		184,171
Operation and maintenance:
Electric, natural gas distribution and pipeline and
energy services		159,072		158,387		141,307
Construction services, natural gas and oil production,
construction materials and mining, independent
power production and other		2,106,855		1,614,053		1,384,015
Depreciation, depletion and amortization		228,657		208,770		188,337
Taxes, other than income		120,023		96,681		80,250
Asset impairments (Notes 1 and 3)		---		6,106		---
		3,007,388		2,398,539		2,040,117
Operating income		448,026		320,718		312,072
Earnings from equity method investments		20,192		25,053		5,968
Other income		7,394		12,707		16,239
Interest expense		54,750		57,437		52,794
Income before income taxes		420,862		301,041		281,485
Income taxes		145,779		93,974		98,572
Income before cumulative effect of accounting change		275,083		207,067		182,913
Cumulative effect of accounting change (Note 8)		---		---		(7,589	)
Net income		275,083		207,067		175,324
Dividends on preferred stocks		685		685		717
Earnings on common stock	$	274,398	$	206,382	$	174,607
Earnings per common share - basic:
Earnings before cumulative effect of accounting change	$	2.31	$	1.77	$	1.64
Cumulative effect of accounting change		---		---		(.07	)
Earnings per common share - basic	$	2.31	$	1.77	$	1.57
Earnings per common share - diluted:
Earnings before cumulative effect of accounting change	$	2.29	$	1.76	$	1.62
Cumulative effect of accounting change		---		---		(.07	)
Earnings per common share - diluted	$	2.29	$	1.76	$	1.55
Dividends per common share	$	.74	$	.70	$	.66
Weighted average common shares outstanding - basic		118,910		116,482		111,483
Weighted average common shares outstanding - diluted		119,660		117,411		112,460

The accompanying notes are an integral part of these consolidated financial statements.

MDU RESOURCES GROUP, INC.

CONSOLIDATED BALANCE SHEETS

December 31,	2005			2004
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	107,435		$	99,377
Receivables, net		603,959			440,903
Inventories		172,201			143,880
Deferred income taxes		9,062			2,874
Prepayments and other current assets		40,539			41,144
		933,196			728,178
Investments		98,217			120,555
Property, plant and equipment (Note 1)		4,594,355			3,931,428
Less accumulated depreciation, depletion and amortization		1,544,462			1,358,723
		3,049,893			2,572,705
Deferred charges and other assets:
Goodwill (Note 3)		230,865			199,743
Other intangible assets, net (Note 3)		19,059			22,269
Other		92,332			90,071
		342,256			312,083
	$	4,423,562		$	3,733,521
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Long-term debt due within one year	$	101,758		$	72,046
Accounts payable		269,021			184,993
Taxes payable		50,533			28,372
Dividends payable		22,951			21,449
Other accrued liabilities		184,665			142,233
		628,928			449,093
Long-term debt (Note 7)		1,104,752			873,441
Deferred credits and other liabilities:
Deferred income taxes		526,176			494,589
Other liabilities		272,084			235,385
		798,260			729,974
Commitments and contingencies (Notes 15, 17 and 18)
Stockholders’ equity:
Preferred stocks (Note 9)		15,000			15,000
Common stockholders’ equity:
Common stock (Note 10)
Authorized - 250,000,000 shares, $1.00 par value
Issued - 120,262,786 shares in 2005 and 118,586,065 shares in 2004		120,263			118,586
Other paid-in capital		909,006			863,449
Retained earnings		884,795			699,095
Accumulated other comprehensive loss		(33,816	)		(11,491	)
Treasury stock at cost - 359,281 shares		(3,626	)		(3,626	)
Total common stockholders’ equity		1,876,622			1,666,013
Total stockholders’ equity		1,891,622			1,681,013
	$	4,423,562		$	3,733,521

The accompanying notes are an integral part of these consolidated financial statements.

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

Years ended December 31, 2005, 2004 and 2003
											Accumulated
					Other						Other
	Common Stock				Paid-in			Retained			Comprehensive			Treasury Stock
	Shares		Amount		Capital			Earnings			Loss			Shares			Amount			Total
	(In thousands, except shares)
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	)
Tax benefit on stock-based
compensation		---		---		2,472			---			---			---			---			2,472
Issuance of common stock
(pre-split)		1,442,220		1,442		42,788			---			---			---			---			44,230
Three-for-two common
stock split (Note 10)		37,862,129		37,862		(37,862	)		---			---			(119,760	)		---			---
Issuance of common stock
(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
Comprehensive income:
Net income		---		---		---			207,067			---			---			---			207,067
Other comprehensive
income (loss), net of tax -
Net unrealized loss on
derivative instruments
qualifying as hedges		---		---		---			---			(1,032	)		---			---			(1,032	)
Minimum pension liability
adjustment		---		---		---			---			(3,782	)		---			---			(3,782	)
Foreign currency
translation adjustment		---		---		---			---			852			---			---			852
Total comprehensive income		---		---		---			---			---			---			---			203,105
Dividends on preferred stocks		---		---		---			(685	)		---			---			---			(685	)
Dividends on common stock		---		---		---			(82,574	)		---			---			---			(82,574	)
Tax benefit on stock-based
compensation		---		---		6,222			---			---			---			---			6,222
Issuance of common stock		4,869,433		4,869		99,440			---			---			---			---			104,309
Balance at
December 31, 2004		118,586,065		118,586		863,449			699,095			(11,491	)		(359,281	)		(3,626	)		1,666,013
Comprehensive income:
Net income		---		---		---			275,083			---			---			---			275,083
Other comprehensive
income (loss), net of tax -
Net unrealized loss on
derivative instruments
qualifying as hedges		---		---		---			---			(21,800	)		---			---			(21,800	)
Minimum pension liability
adjustment		---		---		---			---			574			---			---			574
Foreign currency
translation adjustment		---		---		---			---			(1,099	)		---			---			(1,099	)
Total comprehensive income		---		---		---			---			---			---			---			252,758
Dividends on preferred stocks		---		---		---			(685	)		---			---			---			(685	)
Dividends on common stock		---		---		---			(88,698	)		---			---			---			(88,698	)
Tax benefit on stock-based
compensation		---		---		5,487			---			---			---			---			5,487
Issuance of common stock		1,676,721		1,677		40,070			---			---			---			---			41,747
Balance at
December 31, 2005		120,262,786	$	120,263	$	909,006		$	884,795		$	(33,816	)		(359,281	)	$	(3,626	)	$	1,876,622

The accompanying notes are an integral part of these consolidated financial statements.

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended December 31,	2005			2004			2003
	(In thousands)
Operating activities:
Net income	$	275,083		$	207,067		$	175,324
Cumulative effect of accounting change		---			---			7,589
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation, depletion and amortization		228,657			208,770			188,337
Earnings, net of distributions, from equity
method investments		(14,385	)		(22,261	)		(4,020	)
Deferred income taxes		30,240			33,163			64,587
Asset impairments		---			6,106			---
Changes in current assets and liabilities, net of
acquisitions:
Receivables		(115,252	)		(64,168	)		(9,698	)
Inventories		(20,225	)		(23,799	)		(13,023	)
Other current assets		427			9,659			(13,383	)
Accounts payable		51,197			30,319			2,748
Other current liabilities		25,995			44,172			10,486
Other noncurrent changes		21,502			4,043			9,450
Net cash provided by operating activities		483,239			433,071			418,397

Investing activities:
Capital expenditures		(510,906	)		(337,688	)		(313,053	)
Acquisitions, net of cash acquired		(213,557	)		(37,138	)		(132,653	)
Net proceeds from sale or disposition of property		40,554			20,518			14,439
Investments		1,833			(54,265	)		2,491
Proceeds from sale of equity method investment		38,166			---			---
Proceeds from notes receivable		---			22,000			7,812
Net cash used in investing activities		(643,910	)		(386,573	)		(420,964	)

Financing activities:
Net change in short-term borrowings		---			---			(20,000	)
Issuance of long-term debt		353,937			15,449			219,895
Repayment of long-term debt		(106,822	)		(38,021	)		(105,740	)
Proceeds from issuance of common stock		9,165			70,129			568
Dividends paid		(87,551	)		(81,019	)		(73,371	)
Net cash provided by (used in) financing activities		168,729			(33,462	)		21,352

Increase in cash and cash equivalents		8,058			13,036			18,785
Cash and cash equivalents - beginning of year		99,377			86,341			67,556
Cash and cash equivalents - end of year	$	107,435		$	99,377		$	86,341

The accompanying notes are an integral part of these consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The consolidated financial statements of the Company include the accounts of the following businesses: electric, natural gas distribution, construction services, pipeline and energy services, natural gas and oil production, construction materials and mining, independent power production, and other. The electric, natural gas distribution, and pipeline and energy services businesses are substantially all regulated. Construction services, natural gas and oil production, construction materials and mining, independent power production, and other are nonregulated. For further descriptions of the Company’s businesses, see Note 13. The statements also include the ownership interests in the assets, liabilities and expenses of two jointly owned electric generating facilities.

The Company uses the equity method of accounting for certain investments. For more information on the Company's equity method investments, see Note 2.

The Company's regulated businesses are subject to various state and federal agency regulations. The accounting policies followed by these businesses are generally subject to the Uniform System of Accounts of the 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 SFAS No. 71. 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.

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, 2005 and 2004, was $8.0 million and $6.8 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 was $24.7 million and $24.9 million at December 31, 2005 and 2004, respectively. The remainder of natural gas in underground storage was included in other assets and was $43.2 million and $43.3 million at December 31, 2005 and 2004, respectively.

Inventories

Inventories, other than natural gas in underground storage for the Company’s regulated operations, consisted primarily of aggregates held for resale of $78.1 million and $71.0 million, materials and supplies of $48.7 million and $31.0 million, and other inventories of $20.7 million and $17.0 million, as of December 31, 2005 and 2004, respectively. These inventories were stated at the lower of cost or market.

Property, plant and equipment

Additions to property, plant and equipment are recorded at cost when first placed in service. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost 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 this note, the resulting gains or losses are recognized as a component of income. The Company is permitted to capitalize 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 $11.5 million, $6.2 million and $7.4 million in 2005, 2004 and 2003, 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 aggregate reserves, 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, 2005 and 2004, was as follows:

					Estimated
					Depreciable
					Life
	2005		2004		in Years
	(Dollars in thousands, as applicable)
Regulated:
Electric:
Electric generation, distribution and
transmission plant	$	670,771	$	650,902		4-50
Natural gas distribution:
Natural gas distribution plant		277,288		264,496		4-45
Pipeline and energy services:
Natural gas transmission, gathering
and storage facilities		374,646		358,853		8-104
Nonregulated:
Construction services:
Land		2,533		2,533		---
Buildings and improvements		12,063		10,257		3-40
Machinery, vehicles and equipment		67,439		63,586		2-10
Other		8,075		6,224		3-10
Pipeline and energy services:
Natural gas gathering
and other facilities		146,662		132,067		3-20
Energy services		1,488		1,480		3-7
Natural gas and oil production:
Natural gas and oil properties		1,280,960		973,604		*
Other		22,487		9,021		3-15
Construction materials and mining:
Land		91,613		91,610		---
Buildings and improvements		87,550		51,309		1-40
Machinery, vehicles and equipment		738,568		658,355		1-20
Construction in progress		15,687		16,545		---
Aggregate reserves		377,008		372,649		**
Independent power production:
Electric generation		154,880		154,631		10-30
Construction in progress		234,279		93,953		---
Land		375		375		---
Other		2,077		1,643		3-7
Other:
Land		2,919		3,044		---
Other		24,987		14,291		3-40
Less accumulated depreciation,
depletion and amortization		1,544,462		1,358,723
Net property, plant and equipment	$	3,049,893	$	2,572,705

* Amortized on the units-of-production method based on total proved reserves at an Mcf equivalent average rate of $1.19, $.98 and

$.89 for the years ended December 31, 2005, 2004 and 2003, respectively. Includes natural gas and oil production properties

accounted for under the full-cost method, of which $82.3 million and $69.0 million were excluded from amortization at December

31, 2005 and 2004, respectively.

** Depleted on the units-of-production method based on recoverable aggregate reserves.

Impairment of long-lived assets

The Company reviews the carrying values of its long-lived assets, excluding goodwill and natural gas and oil properties, 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 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. In the third quarter of 2004, the Company recognized a $2.1 million ($1.3 million after tax) adjustment reflecting the reduction in value of certain gathering facilities in the Gulf Coast region at the pipeline and energy services segment. No impairment losses were recorded in 2005 and 2003. 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. 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 the third quarter of 2004, the Company recognized a goodwill impairment at the pipeline and energy services segment. No goodwill impairment losses were recorded in 2005 and 2003. For more information on the goodwill impairment and 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 SEC, plus the cost 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, 2005 and 2004, 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, 2005, 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, 2005, in total and by the year in which such costs were incurred:

			Year Costs Incurred
									2002
	Total		2005		2004		2003		and prior
	(In thousands)
Acquisition	$	38,971	$	13,723	$	3,180	$	481	$	21,587
Development		25,586		15,805		7,567		450		1,764
Exploration		10,124		9,899		225		---		---
Capitalized interest		7,610		2,556		2,039		687		2,328
Total costs not subject
to amortization	$	82,291	$	41,983	$	13,011	$	1,618	$	25,679

Costs not subject to amortization as of December 31, 2005, consisted primarily of unevaluated leaseholds, drilling costs and seismic costs; and capitalized interest associated primarily with coalbed development in the Powder River Basin of Montana and Wyoming, an exploration project in southern Texas, an enhanced recovery development project in the Cedar Creek Anticline in southeastern Montana, the Bakken Play in western North Dakota, and a Red River B prospect in western South Dakota. The Company expects that the majority of these costs will be evaluated within the next five years 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 properties 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 and, where applicable, revenues are recognized under EITF No. 91-6 ratably over the terms of the related contract. 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. If a loss is anticipated on a contract, the loss is immediately recognized. Costs in excess of billings on uncompleted contracts of $52.3 million and $31.9 million at December 31, 2005 and 2004, respectively, represent revenues recognized in excess of amounts billed and were included in receivables, net. Billings in excess of costs on uncompleted contracts of $50.7 million and $32.2 million at December 31, 2005 and 2004, respectively, represent billings in excess of revenues recognized and were 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 $59.5 million and $40.9 million at December 31, 2005 and 2004, 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 that natural gas and oil price derivative instruments and interest rate derivative instruments not exceed a period of 24 months and foreign currency derivative instruments not exceed a 12-month period. 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 on its financial position or results of operations as a result of nonperformance by counterparties. For more information on derivative instruments, see Note 5.

Asset retirement obligations

The Company records 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 Company 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, the Company either settles the obligation for the recorded amount or incurs a gain or loss. For more information on asset retirement obligations, see Note 8.

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 to 28 months from the time such costs are paid. Natural gas costs recoverable through rate adjustments amounted to $691,000 and $15.5 million at December 31, 2005 and 2004, respectively, which is included in prepayments and other current assets.

Insurance

Certain subsidiaries of the Company are insured for workers’ compensation losses, subject to deductibles ranging up to $750,000 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 above the primary automobile and general liability policies 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 for claims incurred but not reported.

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 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-MW natural gas-fired electric generating facility in Brazil, as further discussed in Note 2, was the Brazilian Real. Translation from the Brazilian Real to the U.S. dollar for assets and liabilities was performed using the exchange rate in effect at the balance sheet date. Revenues and expenses had been translated using the weighted average exchange rate for each month prevailing during the period reported. Adjustments resulting from such translations were 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 were 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 10.

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, 2004 and 2003, 36,000 shares and 209,805 shares, respectively, with an average exercise price of $25.70 and $24.56, respectively, attributable to the exercise of outstanding options, were excluded from the calculation of diluted earnings per share because their effect was antidilutive. In 2005, there were no shares excluded from the calculation of diluted 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 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 years ended December 31, 2005, 2004 and 2003, was $2,000, $18,000 and $41,000 respectively (after tax).

As permitted by SFAS No. 148, the Company accounts for stock options granted prior to January 1, 2003, under APB Opinion No. 25. 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.

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, 2005, 2004 and 2003, 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:

	2005			2004			2003
	(In thousands, except per share amounts)
Earnings on common stock, as reported	$	274,398		$	206,382		$	174,607
Stock-based compensation expense
included in reported earnings,
net of related tax effects		2			18			41
Total stock-based compensation expense
determined under fair value method for
all awards, net of related tax effects		(471	)		(62	)		(2,139	)
Pro forma earnings on common stock	$	273,929		$	206,338		$	172,509

Earnings per common share - basic -
as reported:
Earnings before cumulative effect
of accounting change	$	2.31		$	1.77		$	1.64
Cumulative effect of accounting change		---			---			(.07	)
Earnings per common share - basic	$	2.31		$	1.77		$	1.57

Earnings per common share - basic -
pro forma:
Earnings before cumulative effect
of accounting change	$	2.30		$	1.77		$	1.62
Cumulative effect of accounting change		---			---			(.07	)
Earnings per common share - basic	$	2.30		$	1.77		$	1.55

Earnings per common share - diluted
- as reported:
Earnings before cumulative effect
of accounting change	$	2.29		$	1.76		$	1.62
Cumulative effect of accounting change		---			---			(.07	)
Earnings per common share - diluted	$	2.29		$	1.76		$	1.55

Earnings per common share - diluted
- pro forma:
Earnings before cumulative effect
of accounting change	$	2.29		$	1.76		$	1.60
Cumulative effect of accounting change		---			---			(.07	)
Earnings per common share - diluted	$	2.29		$	1.76		$	1.53

For more information on the Company's stock-based compensation, see Note 11.

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, as well as 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. 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,	2005		2004		2003
	(In thousands)
Interest, net of amount capitalized	$	47,902	$	50,236	$	47,474
Income taxes	$	106,771	$	50,487	$	31,737

New accounting standards

SAB No. 106 In September 2004, the SEC issued SAB No. 106, which is an interpretation regarding the application of SFAS No. 143 by oil and gas producing companies following the full-cost accounting method. SAB No. 106 clarifies that the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues for purposes of the full-cost ceiling calculation. SAB No. 106 also states that a company is expected to disclose in the financial statement footnotes and MD&A how the company’s calculation of the ceiling test and depreciation, depletion and amortization are affected by the adoption of SFAS No. 143. SAB No. 106 was effective for the Company as of January 1, 2005. The adoption of SAB No. 106 did not have a material effect on the Company's financial position or results of operations. The effects of the adoption of SFAS No. 143 and SAB No. 106 as they relate to the Company’s natural gas and oil production properties are described below.

Ceiling Test Calculation

As discussed in this note, the Company’s natural gas and oil production properties are subject to a “ceiling test” that limits capitalized 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 SEC, and the cost of unproved properties. Prior to the adoption of SFAS No. 143, the Company calculated the full-cost ceiling by reducing its expected future revenues from proved natural gas and oil reserves by the estimated future expenditures to be incurred in developing and producing such reserves, including future retirements, discounted using a factor mandated by the rules of the SEC. While expected future cash flows related to the asset retirement obligations were included in the calculation of the ceiling test, no associated asset retirement obligation was recognized on the balance sheet.

Upon the adoption of SFAS No. 143 but prior to the effective date of SAB No. 106, the Company continued to calculate the full-cost ceiling as previously described. In addition, the Company recorded the fair value of a liability for the asset retirement obligation and capitalized the cost by increasing the carrying amount of the related long-lived asset.

Upon the adoption of SAB No. 106, the future capitalized discounted cash outflows associated with settling asset retirement obligations that are accrued on the consolidated balance sheet are excluded from the computation of the present value of estimated future net revenues for purposes of the full-cost ceiling calculation in accordance with SAB No. 106.

Depreciation, Depletion and Amortization

Costs subject to amortization include: (A) all capitalized costs, less accumulated amortization, other than the cost of acquiring and evaluating unproved property; (B) the estimated future expenditures (based on current costs) to be incurred in developing proved reserves; and (C) estimated dismantlement and abandonment costs, net of estimated salvage values.

Subsequent to the adoption of SFAS No. 143, the estimated future dismantlement and abandonment costs described in (C) above are included in the capitalized costs described in (A) above at the expected future cost discounted to the present value, to the extent that a legal obligation exists. Under SFAS No. 143, the recognition of the asset retirement obligation does not take into account estimated salvage values. The liability associated with the recognition of an asset retirement obligation is accreted over time with accretion expense recorded in depreciation, depletion and amortization expense on the Consolidated Statements of Income. The Company’s estimated dismantlement and abandonment costs as described in (C) above were adjusted to account for asset retirement obligations accrued on the Consolidated Balance Sheets when calculating the depreciation, depletion and amortization rates. In addition, estimated salvage values were included in the Company’s depreciation, depletion and amortization calculation. The Company’s estimate of future dismantlement and abandonment costs that will be incurred as a result of future development activities on proved reserves continues to be included in the calculation of costs to be amortized.

Any gains or losses on the settlement of an asset retirement obligation, if applicable, are treated as adjustments to the capitalized costs, consistent with the full-cost accounting method.

SFAS No. 123 (revised) In December 2004, the FASB issued SFAS No. 123 (revised). This accounting standard revises SFAS No. 123 and requires entities to recognize compensation expense in an amount equal to the grant-date fair value of share-based payments granted to employees. SFAS No. 123 (revised) is effective for the Company on January 1, 2006. As of the required effective date, the Company will apply SFAS No. 123 (revised) using the modified prospective method, recognizing compensation expense for all awards granted after the date of adoption of SFAS No. 123 (revised) and for the unvested portion of previously granted awards that remain outstanding at the date of adoption. The Company used the Black-Scholes option-pricing model to calculate the fair value of stock options. The Company estimates the adoption of SFAS No. 123 (revised) will result in less than $300,000 (after tax) in additional stock-based compensation expense for the year ended December 31, 2006.

FIN 47 In March 2005, the FASB issued FIN 47. FIN 47 addresses the diverse accounting practices that developed with respect to the timing of liability recognition for legal obligations associated with the retirement of a tangible long-lived asset when the timing and/or method of settlement of the obligation are conditional on a future event. FIN 47 concludes that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective for the Company at the end of the fiscal year ending December 31, 2005. The adoption of FIN 47 did not have a material effect on the Company's financial position or results of operations.

EITF No. 04-6 In March 2005, the FASB ratified EITF No. 04-6. EITF No. 04-6 requires that post-production stripping costs be treated as a variable inventory production cost. As a result, such costs will be subject to inventory costing procedures in the period they are incurred. EITF No. 04-6 is effective for the Company on January 1, 2006. The adoption of EITF No. 04-6 is not expected to have a material effect on the Company’s financial position or results of operations.

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 (losses) on derivative instruments qualifying as hedges, minimum pension liability adjustments and foreign currency translation adjustments. For more information on derivative instruments, see Note 5.

The components of other comprehensive income (loss), and their related tax effects for the years ended December 31, 2005, 2004 and 2003, were as follows:

	2005			2004			2003
	(In thousands)
Other comprehensive income (loss):
Net unrealized gain (loss) on derivative instruments
qualifying as hedges:
Net unrealized loss on derivative instruments
arising during the period, net of tax of
$16,391, $2,734 and $2,132 in 2005,
2004 and 2003, respectively	$	(26,167	)	$	(4,367	)	$	(3,335	)
Less: Reclassification adjustment for loss
on derivative instruments included in net
income, net of tax of $2,734, $2,132 and
$2,903 in 2005, 2004 and 2003, respectively		(4,367	)		(3,335	)		(4,541	)
Net unrealized gain (loss) on derivative
instruments qualifying as hedges		(21,800	)		(1,032	)		1,206
Minimum pension liability adjustment, net
of tax of $353, $2,406 and $38 in 2005,
2004 and 2003, respectively		574			(3,782	)		21
Foreign currency translation adjustment		(1,099	)		852			1,048
Total other comprehensive income (loss)	$	(22,325	)	$	(3,962	)	$	2,275

The after-tax components of accumulated other comprehensive loss as of December 31, 2005, 2004 and 2003, were as follows:

	Net Unrealized Loss on Derivative Instruments Qualifying as Hedges			Minimum Pension Liability Adjustment			Foreign Currency Translation Adjustment		Total Accumulated Other Comprehensive Loss
				(In thousands)
Balance at December 31, 2003	$	(3,335	)	$	(4,443	)	$	249	$	(7,529	)
Balance at December 31, 2004	$	(4,367	)	$	(8,225	)	$	1,101	$	(11,491	)
Balance at December 31, 2005	$	(26,167	)	$	(7,651	)	$	2	$	(33,816	)

NOTE 2 - EQUITY METHOD INVESTMENTS

The Company has a number of equity method investments including Carib Power and Hartwell. The Company assesses its equity method investments for impairment whenever events or changes in circumstances indicate that the related carrying values may not be recoverable. None of the Company’s equity method investments have been impaired and, accordingly, no impairment losses have been recorded in the accompanying consolidated financial statements or related equity method investment balances.

In February 2004, Centennial International acquired 49.99 percent of Carib Power. Carib Power, through a wholly owned subsidiary, owns a 225-MW natural gas-fired electric generating facility in Trinidad and Tobago. The Trinity Generating Facility sells its output to the T&TEC, the governmental entity responsible for the transmission, distribution and administration of electrical power to the national electrical grid of Trinidad and Tobago. The power purchase agreement expires in September 2029. T&TEC also is under contract to supply natural gas to the Trinity Generating Facility during the term of the power purchase agreement. The functional currency for the Trinity Generating Facility is the U.S. dollar.

In September 2004, Centennial Resources, through indirect wholly owned subsidiaries, acquired a 50-percent ownership interest in Hartwell, which owns a 310-MW natural gas-fired electric generating facility near Hartwell, Georgia. The Hartwell Generating Facility sells its output under a power purchase agreement with Oglethorpe that expires in May 2019. Oglethorpe reimburses the Hartwell Generating Facility for actual costs of fuel required to operate the plant. American National Power, a wholly owned subsidiary of International Power of the United Kingdom, holds the remaining 50-percent ownership interest and is the operating partner for the facility.

In June 2005, the Company completed the sale of its 49 percent interest in MPX to Petrobras, the Brazilian state-controlled energy company. The Company realized a gain of $15.6 million from the sale in the second quarter of 2005. MPX owns and operates the Termoceara Generating Facility in the Brazilian state of Ceara. Petrobras had entered into a contract to purchase all of the capacity and market all of the energy from the Termoceara Generating Facility. The electric power sales contract with Petrobras was scheduled to expire in mid-2008.

The functional currency for the Termoceara Generating Facility was the Brazilian Real. The electric power sales contract with Petrobras contained an embedded derivative, which derived its value from an annual adjustment factor, which largely indexed the contract capacity payments to the U.S. dollar. The Company's 49 percent share of the gain from the change in fair value of the embedded derivative in the electric power sales contract for the year ended December 31, 2004, was $2.5 million (after tax). The Company's 49 percent share of the loss from the change in fair value of the embedded derivative in the electric power sales contract for the year ended December 31, 2003, was $11.3 million (after tax). The Company's 49 percent share of the foreign currency gain resulting from an increase in value of the Brazilian Real versus the U.S. dollar for the years ended December 31, 2004 and 2003, was $1.9 million (after tax) and $2.8 million (after tax), respectively.

In 2005, the Termoceara Generating Facility was accounted for as an asset held for sale and, as a result, no depreciation, depletion and amortization expense was recorded in 2005.

At December 31, 2005, the Company’s equity method investments, including Carib Power and Hartwell, had total assets of $231.9 million and long-term debt of $154.8 million. At December 31, 2004, the Company’s equity method investments, including MPX, Carib Power and Hartwell, had total assets of $334.2 million and long-term debt of $224.9 million. The Company’s investment in its equity method investments, including the Trinity and Hartwell Generating Facilities, was approximately $41.8 million, including undistributed earnings of $3.5 million, at December 31, 2005. The Company’s investment in the Termoceara, Trinity and Hartwell Generating Facilities was approximately $65.7 million, including undistributed earnings of $26.6 million, at December 31, 2004.

NOTE 3 - GOODWILL AND OTHER INTANGIBLE ASSETS

The changes in the carrying amount of goodwill for the year ended December 31, 2005, were as follows:

	Balance		Goodwill			Balance
	as of		Acquired			as of
	January 1,		During			December 31,
	2005		the Year*			2005
	(In thousands)
Electric	$	---	$	---		$	---
Natural gas distribution		---		---			---
Construction services		62,632		18,338			80,970
Pipeline and energy services		5,464		---			5,464
Natural gas and oil production		---		---			---
Construction materials and mining		120,452		12,812			133,264
Independent power production		11,195		(28	)		11,167
Other		---		---			---
Total	$	199,743	$	31,122		$	230,865

*	Includes purchase price adjustments that were not material related to acquisitions in a prior period.

The changes in the carrying amount of goodwill for the year ended December 31, 2004, were as follows:

	Balance		Goodwill		Goodwill			Balance
	as of		Acquired		Impaired			as of
	January 1,		During		During			December 31,
	2004		the Year*		the Year			2004
	(In thousands)
Electric	$	---	$	---	$	---		$	---
Natural gas distribution		---		---		---			---
Construction services		62,604		28		---			62,632
Pipeline and energy services		9,494		---		(4,030	)		5,464
Natural gas and oil production		---		---		---			---
Construction materials and mining		120,198		254		---			120,452
Independent power production		7,131		4,064		---			11,195
Other		---		---		---			---
Total	$	199,427	$	4,346	$	(4,030	)	$	199,743

* Includes purchase price adjustments that were not material related to acquisitions in a prior period.

Innovatum, which specializes in cable and pipeline magnetization and location, developed a hand-held locating device that can detect both magnetic and plastic materials, including unexploded ordnance. Innovatum was working with, and had demonstrated the device to, a Department of Defense contractor and had also met with individuals from the Department of Defense to discuss the possibility of using the hand-held locating device in their operations. In the third quarter of 2004, after communications with the Department of Defense and delays in further testing resulting from a Department of Defense request to enhance the hand-held locating device, Innovatum decreased its expected future cash flows from the hand-held locating device. This decrease, coupled with the downturn in the telecommunications and energy industries, resulted in a revised earnings forecast for Innovatum and, as a result, a goodwill impairment loss of $4.0 million (before and after tax), which was included in asset impairments, was recognized in the third quarter of 2004. Innovatum, a reporting unit for goodwill impairment testing, is part of the pipeline and energy services segment. The fair value of Innovatum was estimated using the expected present value of future cash flows.

Other intangible assets at December 31, 2005 and 2004, were as follows:

	2005			2004
	(In thousands)
Amortizable intangible assets:
Acquired contracts	$	18,065		$	15,041
Accumulated amortization		(9,458	)		(5,013	)
		8,607			10,028
Noncompete agreements		11,784			10,575
Accumulated amortization		(8,557	)		(8,186	)
		3,227			2,389
Other		7,914			9,535
Accumulated amortization		(1,213	)		(534	)
		6,701			9,001
Unamortizable intangible assets		524			851
Total	$	19,059		$	22,269

The unamortizable intangible assets were recognized in accordance with SFAS No. 87, 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, 2005, 2004 and 2003, was $5.5 million, $3.8 million and $2.2 million, respectively. Estimated amortization expense for amortizable intangible assets is $3.5 million in 2006, $2.7 million in 2007, $2.6 million in 2008, $2.6 million in 2009, $2.2 million in 2010 and $4.9 million thereafter.

NOTE 4 - REGULATORY ASSETS AND LIABILITIES

The following table summarizes the individual components of unamortized regulatory assets and liabilities as of December 31:

	2005			2004
	(In thousands)
Regulatory assets:
Deferred income taxes	$	38,757		$	39,212
Plant costs		13,122			12,838
Long-term debt refinancing costs		3,160			3,531
Natural gas costs recoverable through rate adjustments		691			15,534
Other		6,519			7,732
Total regulatory assets		62,249			78,847
Regulatory liabilities:
Plant removal and decommissioning costs		78,280			78,525
Taxes refundable to customers		14,966			15,660
Deferred income taxes		10,298			15,192
Liabilities for regulatory matters		7,405			18,853
Other		4,830			3,676
Total regulatory liabilities		115,779			131,906
Net regulatory position	$	(53,530	)	$	(53,059	)

As of December 31, 2005, a large portion of the Company's regulatory assets, other than certain deferred income taxes, was being reflected in rates charged to customers and is being recovered over the next one to 17 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

Derivative instruments, including certain derivative instruments embedded in other contracts, are required to be recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative instrument’s fair value are 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.

As of December 31, 2005, Fidelity held derivative instruments designated as cash flow hedging instruments.

Hedging activities

For the years ended December 31, 2005, 2004 and 2003, the amount of hedge ineffectiveness, which was included in operating revenues, was immaterial. For the years ended December 31, 2005, 2004 and 2003, Fidelity 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, 2005, the maximum term of Fidelity’s swap and collar agreements, in which Fidelity is hedging its exposure to the variability in future cash flows for forecasted transactions, is 12 months. The Company estimates that over the next 12 months, net losses of approximately $25.8 million will be reclassified from accumulated other comprehensive loss into earnings, subject to changes in natural gas and oil market prices, as the hedged transactions affect earnings.

NOTE 6 - FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS

The estimated fair value of the Company's long-term debt is based on quoted market prices of the same or similar issues. 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, 2005 and 2004. The estimated fair values of the Company's natural gas and oil price swap and collar agreements 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 and natural gas and oil price swap and collar agreement obligations at December 31 was as follows:

	2005				2004
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In thousands)
Long-term debt	$	1,206,510	$	1,219,347	$	945,487	$	992,172
Natural gas and oil
price swap and
collar agreement obligations	$	42,011	$	42,011	$	7,101	$	7,101

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 - LONG-TERM DEBT AND INDENTURE PROVISIONS

Long-term debt outstanding at December 31 was as follows:

	2005			2004
	(In thousands)
First mortgage bonds and notes:
Pollution Control Refunding Revenue Bonds, Series 1992,
6.65%, redeemed in 2005	$	---		$	20,850
Secured Medium-Term Notes, Series A, at a weighted
average rate of 7.75%, due on dates ranging from
April 1, 2007 to April 1, 2012		95,000			95,000
Senior Notes, 5.98%, due December 15, 2033		30,000			30,000
Total first mortgage bonds and notes		125,000			145,850
Senior notes at a weighted average rate of 5.83%,
due on dates ranging from May 31, 2006
to July 1, 2019		815,000			728,500
Commercial paper at a weighted average rate of 4.33%,
supported by revolving credit agreements		260,000			63,000
Term credit agreements at a weighted average rate of 6.60%,
due on dates ranging from March 31, 2006
to December 1, 2013		6,623			8,172
Discount		(113	)		(35	)
Total long-term debt		1,206,510			945,487
Less current maturities		101,758			72,046
Net long-term debt	$	1,104,752		$	873,441

The amounts of scheduled long-term debt maturities for the five years and thereafter following December 31, 2005, aggregate $101.8 million in 2006; $106.9 million in 2007; $161.3 million in 2008; $86.9 million in 2009; $266.8 million in 2010 and $482.8 million thereafter.

MDU Resources Group, Inc.

The Company has a revolving credit agreement with various banks totaling $100 million (with provision for an increase, at the option of the Company on stated conditions, up to a maximum of $125 million). There were no amounts outstanding under the credit agreement at December 31, 2005 and 2004. The credit agreement supports the Company’s $100 million (previously $75 million) commercial paper program. Under the Company’s commercial paper program, $60.0 million and $37.0 million were outstanding at December 31, 2005 and 2004, respectively, which was classified as long-term debt. The commercial paper borrowings are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings (supported by the credit agreement, which expires in June 2010).

There are no credit facilities that contain cross-default provisions between the Company and any of its subsidiaries.

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 fund $1.43 of unfunded property or use $1.00 of refunded bonds for each dollar of indebtedness incurred under the Indenture and, in some cases, to certify to the trustee 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 tests, as of December 31, 2005, the Company could have issued approximately $364 million of additional first mortgage bonds.

Approximately $430.7 million in net book value of the Company’s net electric and natural gas distribution properties at December 31, 2005, 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 has three revolving credit agreements with various banks and institutions totaling $441.4 million with certain provisions allowing for increased borrowings. These credit agreements support Centennial’s $350 million commercial paper program. There were no outstanding borrowings under the Centennial credit agreements at December 31, 2005 or 2004. Under the Centennial commercial paper program, $200.0 million and $26.0 million were outstanding at December 31, 2005 and 2004, 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 (supported by Centennial credit agreements). One of these credit agreements is for $400 million, which includes a provision for an increase, at the option of Centennial on stated conditions, up to a maximum of $450 million and expires on August 26, 2010. Another agreement is for $21.4 million and expires on April 30, 2007. Pursuant to this credit agreement, on the last business day of April 2006, the line of credit will be reduced by $3.6 million. Centennial intends to negotiate the extension or replacement of these agreements prior to their maturities. The third agreement is an uncommitted line for $20 million, which was effective on January 27, 2006, and may be terminated by the bank at any time. As of December 31, 2005, $32.3 million of letters of credit were outstanding, as discussed in Note 18, of which $14.9 million were outstanding under the above credit agreements that reduced amounts available under these agreements.

Centennial has an uncommitted long-term master shelf agreement that allows for borrowings of up to $450 million. Under the terms of the master shelf agreement, $447.5 million and $384.0 million were outstanding at December 31, 2005 and 2004, respectively. The ability to request additional borrowings under this master shelf agreement expires in April 2008. To meet potential future financing needs, Centennial may pursue other financing arrangements, including private and/or public financing.

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, 2005 and 2004. The ability to request additional borrowings under this master shelf agreement expires on December 20, 2007.

NOTE 8 - ASSET RETIREMENT OBLIGATIONS

The Company adopted SFAS No. 143 on January 1, 2003. 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. 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 adopted FIN 47 on December 31, 2005, as discussed in Note 1. The Company recorded obligations related to special handling and disposal of hazardous materials at certain electric generating and distribution facilities, natural gas distribution and transmission facilities, and buildings. Upon adoption of FIN 47, the Company recorded an additional discounted liability of $1.7 million and a regulatory asset of $1.5 million and increased net property, plant and equipment by $151,000. There was no impact on net income; therefore pro forma presentation amounts assuming retroactive application of the accounting change on net income are not necessary.

A reconciliation of the Company's liability, which is included in other liabilities, for the years ended December 31 was as follows:

	2005			2004
	(In thousands)
Balance at beginning of year	$	37,350		$	34,633
Liabilities incurred		3,786			3,718
Liabilities acquired		1,138			178
Liabilities settled		(3,328	)		(2,286	)
Accretion expense		2,241			1,931
Revisions in estimates		740			(824	)
Liabilities recorded upon adoption of FIN 47		1,663			---
Other		47			---
Balance at end of year	$	43,637		$	37,350

The following reconciliation of the Company’s liability for the years ended December 31 includes the pro forma effects of the adoption of FIN 47 for all years presented.

	2005			2004
	(In thousands)
Balance at beginning of year	$	38,924		$	36,122
Liabilities incurred		3,786			3,718
Liabilities acquired		1,138			178
Liabilities settled		(3,328	)		(2,286	)
Accretion expense		2,241			1,931
Revisions in estimates		740			(824	)
Other		136			85
Balance at end of year	$	43,637		$	38,924

The Company believes that any expenses under SFAS No. 143 and FIN 47 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 expenses that it believes will be recovered in rates over time.

The fair value of assets that are legally restricted for purposes of settling asset retirement obligations at December 31, 2005 and 2004, was $5.1 million and $5.2 million, respectively.

NOTE 9 - PREFERRED STOCKS

Preferred stocks at December 31 were as follows:

	2005		2004
	(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:
4.50% Series - 100,000 shares	$	10,000	$	10,000
4.70% Series - 50,000 shares		5,000		5,000
Total preferred stocks	$	15,000	$	15,000

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 per share and $102 per share, 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 bylaws 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 10 - 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.

In 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 share of 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.

The 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 K-Plan is partially funded with the Company's common stock. Since January 1, 2003, 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, 2005, there were 12.1 million shares of common stock reserved for original issuance under the Stock Purchase Plan and K-Plan.

NOTE 11 - 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, 2005, 2004 and 2003, 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, 2005, 2004 and 2003, and changes during the years then ended were as follows:

	2005					2004					2003
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
	Shares			Price		Shares			Price		Shares			Price
Balance at
beginning of year		2,561,684		$	19.29		4,182,456		$	19.09		4,861,268		$	18.58
Granted		---			---		---			---		27,015			17.29
Forfeited		(114,552	)		20.30		(382,942	)		19.64		(188,486	)		20.05
Exercised		(589,150	)		18.48		(1,237,830	)		18.49		(517,341	)		13.88
Balance at end
of year		1,857,982			19.48		2,561,684			19.29		4,182,456			19.09
Exercisable at
end of year		1,093,523		$	18.86		1,700,223		$	18.73		611,404		$	15.06

Summarized information about stock options outstanding and exercisable as of December 31, 2005, 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		10,125		1.5	$	10.92		10,125	$	10.92
13.01 - 17.00		234,535		2.5		14.39		231,889		14.38
17.01 - 21.00		1,438,992		5.2		19.76		785,874		19.78
21.01 - 25.70		174,330		5.2		24.51		65,635		24.87
Balance at end of year		1,857,982		4.8		19.48		1,093,523		18.86

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:

	2005		2004		2003
Weighted average fair value of options at grant date		---		---	$	4.67
Weighted average risk-free interest rate		---		---		3.91	%
Weighted average expected price volatility		---		---		32.28	%
Weighted average expected dividend yield		---		---		3.43	%
Expected life in years		---		---		7

In addition, prior to 2002 the Company granted restricted stock awards under a long-term incentive plan and deferred compensation agreements. The restricted stock awards granted vest to the participants at various times ranging from one year 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 Company also has granted stock awards totaling 28,586 shares, 35,205 shares and 31,855 shares in 2005, 2004 and 2003, respectively, under a nonemployee director stock compensation plan. The weighted average grant date fair value of the stock grants was $28.32, $23.61 and $21.40 in 2005, 2004 and 2003, 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 $1.8 million, $3.4 million and $4.8 million in 2005, 2004 and 2003, respectively.

In 2005, 2004 and 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:


Grant Date	Performance Period		Target Grant of Shares
February 2003		2003-2005		54,180
February 2004		2004-2006		185,743
February 2005		2005-2007		182,927

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 years ended December 31, 2005, 2004 and 2003, was $3.6 million, $2.5 million and $879,000, respectively.

The Company is authorized to grant options, restricted stock and stock for up to 12.7 million shares of common stock and has granted options, restricted stock and stock on 5.8 million shares through December 31, 2005.

NOTE 12 - INCOME TAXES

The components of income before income taxes for each of the years ended December 31 were as follows:

	2005		2004		2003
			(In thousands)
United States	$	407,118	$	280,764	$	278,143
Foreign		13,744		20,277		3,342
Income before income taxes	$	420,862	$	301,041	$	281,485

Income tax expense for the years ended December 31 was as follows:

	2005			2004			2003
	(In thousands)
Current:
Federal	$	95,153		$	47,625		$	26,313
State		20,575			12,231			7,408
Foreign		(189	)		955			264
	$	115,539			60,811			33,985
Deferred:
Income taxes -
Federal		25,726			28,556			55,660
State		5,014			5,422			9,861
Foreign		---			(223	)		(338	)
Investment tax credit		(500	)		(592	)		(596	)
		30,240			33,163			64,587
Total income tax expense	$	145,779		$	93,974		$	98,572

Components of deferred tax assets and deferred tax liabilities recognized at December 31 were as follows:

	2005			2004
	(In thousands)
Deferred tax assets:
Regulatory matters	$	38,757		$	39,212
Accrued pension costs		22,000			18,754
Natural gas and oil price swap and collar agreements		16,375			2,734
Deferred compensation		13,057			9,938
Asset retirement obligations		13,017			12,197
Bad debts		2,804			2,266
Deferred investment tax credit		530			724
Other		31,288			26,503
Total deferred tax assets		137,828			112,328
Deferred tax liabilities:
Depreciation and basis differences on property,
plant and equipment		465,637			450,237
Basis differences on natural gas and oil
producing properties		159,077			124,788
Regulatory matters		10,298			15,192
Other		19,930			13,826
Total deferred tax liabilities		654,942			604,043
Net deferred income tax liability	$	(517,114	)	$	(491,715	)

As of December 31, 2005 and 2004, 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, 2004, to December 31, 2005, to deferred income tax expense:

	2005
	(In thousands)
Change in net deferred income tax
liability from the preceding table	$	25,399
Deferred taxes associated with other comprehensive income		13,304
Deferred taxes associated with acquisitions		(6,825	)
Other		(1,638	)
Deferred income tax expense for the period	$	30,240

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,	2005						2004						2003
	Amount			%			Amount			%			Amount			%
	(Dollars in thousands)
Computed tax at federal
statutory rate	$	147,302			35.0		$	105,364			35.0		$	98,520			35.0
Increases (reductions)
resulting from:
State income taxes,
net of federal
income tax benefit		15,459			3.7			11,468			3.8			11,857			4.2
Depletion allowance		(4,381	)		(1.1	)		(3,418	)		(1.2	)		(3,117	)		(1.1	)
Foreign operations		(4,209	)		(1.0	)		(5,648	)		(1.9	)		(832	)		(.3	)
Renewable electricity
production credit		(4,087	)		(1.0	)		(3,404	)		(1.1	)		(3,395	)		(1.2	)
Audit resolution		---			---			(8,818	)		(2.9	)		---			---
Other items		(4,305	)		(1.0	)		(1,570	)		(.5	)		(4,461	)		(1.6	)
Total income tax expense	$	145,779			34.6		$	93,974			31.2		$	98,572			35.0

In 2004, the Company resolved federal and related state income tax matters for the 1998 through 2000 tax years. The Company reflected the effects of this tax resolution and, in addition, reversed liabilities that had previously been provided and were deemed to be no longer required, which resulted in a benefit of $8.3 million (after tax), including interest.

The Company considers earnings (including the gain from the sale of 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. The cumulative undistributed earnings at December 31, 2005, were approximately $36 million. The amount of unrecognized deferred tax liability associated with the undistributed earnings was approximately $9.5 million.

NOTE 13 - 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 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 investments in natural resource-based projects.

The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states as well as in western Minnesota. These operations also supply related value-added products and services.

The construction 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, development and production activities primarily in the Rocky Mountain and Mid-Continent regions 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 Alaska and Hawaii.

The independent power production segment owns, builds and operates electric generating facilities in the United States and has investments in domestic and international natural resource-based projects. Electric capacity and energy produced at its power plants primarily are sold under mid-and long-term contracts to nonaffiliated entities.

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:

	2005			2004			2003
	(In thousands)
External operating revenues:
Electric	$	181,238		$	178,803		$	178,562
Natural gas distribution		384,199			316,120			274,608
Pipeline and energy services		387,870			281,913			187,892
		953,307			776,836			641,062
Construction services		686,734			425,250			434,177
Natural gas and oil production		163,539			152,486			140,281
Construction materials and mining		1,603,326			1,321,626			1,104,408
Independent power production		48,508			43,059			32,261
Other		---			---			---
		2,502,107			1,942,421			1,711,127
Total external operating revenues	$	3,455,414		$	2,719,257		$	2,352,189

Intersegment operating revenues:
Electric	$	---		$	---		$	---
Natural gas distribution		---			---			---
Construction services		391			1,571			---
Pipeline and energy services		92,424			75,316			64,300
Natural gas and oil production		275,828			190,354			124,077
Construction materials and mining		1,284			535			---
Independent power production		---			---			---
Other		6,038			4,423			2,728
Intersegment eliminations		(375,965	)		(272,199	)		(191,105	)
Total intersegment
operating revenues	$	---		$	---		$	---

Depreciation, depletion and
amortization:
Electric	$	20,818		$	20,199		$	20,150
Natural gas distribution		9,534			9,329			10,044
Construction services		13,459			11,113			10,353
Pipeline and energy services		12,784			17,804			15,016
Natural gas and oil production		84,754			70,823			61,019
Construction materials and mining		77,988			69,644			63,601
Independent power production		8,990			9,587			7,860
Other		330			271			294
Total depreciation, depletion
and amortization	$	228,657		$	208,770		$	188,337

Interest expense:
Electric	$	7,553		$	9,116		$	8,013
Natural gas distribution		3,973			4,292			3,936
Construction services		4,177			3,442			3,668
Pipeline and energy services		8,498			9,262			7,952
Natural gas and oil production		7,550			7,552			4,767
Construction materials and mining		21,365			20,646			18,747
Independent power production		2,260			4,354			5,850
Other		(399	)		(70	)		15
Intersegment eliminations		(227	)		(1,157	)		(154	)
Total interest expense	$	54,750		$	57,437		$	52,794

Income taxes:
Electric	$	8,308		$	4,303		$	9,862
Natural gas distribution		2,240			(3,883	)		1,823
Construction services		9,693			(3,345	)		3,905
Pipeline and energy services		13,004			7,445			11,188
Natural gas and oil production		82,428			61,261			42,993
Construction materials and mining		29,244			26,674			28,168
Independent power production		483			1,249			257
Other		379			270			376
Total income taxes	$	145,779		$	93,974		$	98,572

Cumulative effect of accounting
change (Note 8):
Electric	$	---		$	---		$	---
Natural gas distribution		---			---			---
Construction services		---			---			---
Pipeline and energy services		---			---			---
Natural gas and oil production		---			---			(7,740	)
Construction materials and mining		---			---			151
Independent power production		---			---			---
Other		---			---			---
Total cumulative effect of
accounting change	$	---		$	---		$	(7,589	)

Earnings on common stock:
Electric	$	13,940		$	12,790		$	16,950
Natural gas distribution		3,515			2,182			3,869
Construction services		14,558			(5,650	)		6,170
Pipeline and energy services		22,092			8,944			18,158
Natural gas and oil production		141,625			110,779			63,027
Construction materials and mining		55,040			50,707			54,412
Independent power production		22,921			26,309			11,415
Other		707			321			606
Total earnings on common stock	$	274,398		$	206,382		$	174,607

Capital expenditures:
Electric	$	27,036		$	18,767		$	28,537
Natural gas distribution		17,224			17,384			15,672
Construction services		50,900			8,470			7,820
Pipeline and energy services		36,399			38,282			93,004
Natural gas and oil production		329,773			111,506			101,698
Construction materials and mining		161,977			133,080			128,487
Independent power production		135,778			76,246			110,963
Other		11,913			4,215			1,895
Net proceeds from sale or
disposition of property		(40,554	)		(20,518	)		(14,439	)
Total net capital expenditures	$	730,446		$	387,432		$	473,637

Identifiable assets:
Electric*	$	330,327		$	323,819		$	327,899
Natural gas distribution*		271,653			252,582			234,948
Construction services		351,654			230,955			221,824
Pipeline and energy services		466,961			447,302			405,904
Natural gas and oil production		898,883			685,610			602,389
Construction materials and mining		1,498,338			1,345,547			1,248,607
Independent power production		483,900			349,752			241,918
Other**		121,846			97,954			97,103
Total identifiable assets	$	4,423,562		$	3,733,521		$	3,380,592

Property, plant and equipment:
Electric*	$	670,771		$	650,902		$	639,893
Natural gas distribution*		277,288			264,496			252,591
Construction services		90,110			82,600			76,871
Pipeline and energy services		522,796			492,400			461,793
Natural gas and oil production		1,303,447			982,625			871,357
Construction materials and mining		1,310,426			1,190,468			1,080,399
Independent power production		391,611			250,602			184,127
Other		27,906			17,335			17,007
Less accumulated depreciation,
depletion and amortization		1,544,462			1,358,723			1,187,105
Net property, plant and equipment	$	3,049,893		$	2,572,705		$	2,396,933

* Includes allocations of common utility property.

**	Includes assets not directly assignable to a business (i.e. cash and cash equivalents, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).

Excluding the asset impairments at pipeline and energy services of $5.3 million (after tax) in 2004, earnings (loss) from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings from construction services, natural gas and oil production, construction materials and mining, independent power production, and other are all from nonregulated operations. Capital expenditures for 2005, 2004 and 2003 include noncash transactions, including the issuance of the Company's equity securities in connection with acquisitions. The noncash transactions were $46.5 million, $33.1 million and $42.4 million in 2005, 2004 and 2003, respectively.

NOTE 14 - ACQUISITIONS

In 2004, the Company acquired a number of businesses including construction materials and mining businesses in Hawaii, Idaho, Iowa and Minnesota and an independent power production operating and development company in Colorado, none of which was material. The total purchase consideration for these businesses and purchase price adjustments with respect to certain other acquisitions acquired prior to 2004, consisting of the Company's common stock and cash, was $70.3 million.

In 2003, the Company acquired a number of businesses including construction materials and mining businesses in Montana, North Dakota and Texas and a wind-powered electric generating facility in California, none of which was material. The total purchase consideration for these businesses and purchase price adjustments with respect to certain other acquisitions acquired in 2002, consisting of the Company's common stock and cash, was $175.0 million.

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. On certain of the above acquisitions made in 2005, final fair market values are pending the completion of the review of the relevant assets, liabilities and issues identified as of the acquisition date. The results of operations of the acquired businesses and properties 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 15 - EMPLOYEE BENEFIT PLANS

The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Effective January 1, 2006, the Company discontinued defined pension plan benefits to all nonunion and certain union employees hired after December 31, 2005. These employees that would have been eligible for defined pension plan benefits are eligible to receive additional defined contribution plan benefits. The Company uses a measurement date of December 31 for all of its pension and postretirement benefit plans. The Company recognized the effects of the 2003 Medicare Act during the second quarter of 2004. The net periodic benefit cost for 2004 reflects the effects of the 2003 Medicare Act. 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
	2005			2004			2005			2004
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning
of year	$	284,756		$	261,335		$	75,491		$	88,381
Service cost		8,336			7,667			1,719			1,826
Interest cost		16,617			15,903			3,784			4,312
Plan participants’ contributions		---			---			1,386			1,133
Amendments		451			---			743			(773	)
Actuarial (gain) loss		7,046			12,240			(8,924	)		(14,951	)
Benefits paid		(13,813	)		(12,389	)		(4,388	)		(4,437	)
Benefit obligation at end of year		303,393			284,756			69,811			75,491

Change in plan assets:
Fair value of plan assets at
beginning of year		239,522			223,043			50,978			47,234
Actual gain on plan assets		16,805			27,264			1,419			2,920
Employer contribution		2,814			1,604			3,053			4,127
Plan participants’ contributions		---			---			1,386			1,134
Benefits paid		(13,813	)		(12,389	)		(4,388	)		(4,437	)
Fair value of plan assets at end
of year		245,328			239,522			52,448			50,978

Funded status - under		(58,065	)		(45,234	)		(17,363	)		(24,513	)
Unrecognized actuarial (gain) loss		55,097			46,293			(7,621	)		(1,832	)
Unrecognized prior service cost		6,861			7,435			694			---
Unrecognized net transition
obligation (asset)		(3	)		(47	)		14,878			16,999
Prepaid (accrued) benefit cost	$	3,890		$	8,447			(9,412	)	$	(9,346	)

Amounts recognized in the
Consolidated Balance Sheets
at December 31:
Prepaid benefit cost	$	18,690		$	19,020		$	787		$	572
Accrued benefit liability		(14,800	)		(10,573	)		(10,199	)		(9,918	)
Additional minimum liability		(1,434	)		---			---			---
Intangible asset		524			---			---			---
Accumulated other comprehensive income		910			---			---			---
Net amount recognized	$	3,890		$	8,447		$	(9,412	)	$	(9,346	)

Employer contributions and benefits paid in the above table include only those amounts contributed directly to, or paid directly from, plan assets.

Unrecognized pension actuarial losses in excess of 10 percent of the greater of the projected benefit obligation or the market-related value of assets is amortized on a straight-line basis over the expected average remaining service lives of active participants. Unrecognized postretirement net transition obligation is amortized over a 20-year period ending 2012.

The accumulated benefit obligation for the defined benefit pension plans reflected above was $244.3 million and $227.3 million at December 31, 2005 and 2004, 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, 2005 and 2004, were as follows:

	2005		2004
	(In thousands)
Projected benefit obligation	$	190,877	$	174,983
Accumulated benefit obligation	$	151,399	$	136,012
Fair value of plan assets	$	139,108	$	132,280

Components of net periodic benefit cost for the Company’s pension and other postretirement benefit plans were as follows:

										Other
	Pension									Postretirement
	Benefits									Benefits
Years ended December 31,	2005			2004			2003			2005			2004			2003
	(In thousands)
Components of net periodic
benefit cost:
Service cost	$	8,336		$	7,667		$	5,897		$	1,719		$	1,826		$	1,857
Interest cost		16,617			15,903			15,211			3,784			4,312			5,281
Expected return on assets		(19,947	)		(20,375	)		(20,730	)		(4,005	)		(3,943	)		(3,933	)
Amortization of prior
service cost		1,025			1,121			1,156			45			144			48
Recognized net actuarial
(gain) loss		1,385			480			(417	)		(549	)		(233	)		(255	)
Amortization of net transition
obligation (asset)		(45	)		(250	)		(950	)		2,126			2,151			2,151
Net periodic benefit cost		7,371			4,546			167			3,120			4,257			5,149
Less amount capitalized		730			409			14			313			440			601
Net periodic benefit cost	$	6,641		$	4,137		$	153		$	2,807		$	3,817		$	4,548

Weighted average assumptions used to determine benefit obligations at December 31 were as follows:

	Pension Benefits					Other Postretirement Benefits
		2005		2004			2005		2004

Discount rate		5.50	%	5.75	%		5.50	%	5.75	%
Rate of compensation increase		4.30	%	4.70	%		4.50	%	4.50	%

Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31 were as follows:

	Pension Benefits						Other Postretirement Benefits
	2005			2004			2005			2004

Discount rate		5.75	%		6.00	%		5.75	%		6.00	%
Expected return on plan assets		8.50	%		8.50	%		7.50	%		7.50	%
Rate of compensation increase		4.70	%		4.70	%		4.50	%		4.50	%

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:

	2005			2004
Health care trend rate assumed for next year		6.0%-9.5	%		6.0%-9.5	%
Health care cost trend rate - ultimate		5.0%-6.0	%		5.0%-6.0	%
Year in which ultimate trend rate achieved		1999-2014			1999-2013

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, 2005:

	1 Percentage			1 Percentage
	Point Increase			Point Decrease
	(In thousands)
Effect on total of service
and interest cost components	$	(77	)	$	(770	)
Effect on postretirement
benefit obligation	$	441		$	(7,499	)

The Company's defined benefit pension plans’ asset allocation at December 31, 2005 and 2004, and weighted average targeted asset allocations at December 31, 2005, were as follows:

							Weighted Average
	Percentage						Targeted Asset
	of Plan						Allocation
	Assets						Percentage
Asset Category	2005			2004			2005
Equity securities		74	%		74	%		70	%
Fixed income securities		21			24			30	*
Other		5			2			---
Total		100	%		100	%		100	%

* Includes target for both fixed income securities and other.

The Company's pension assets are managed by 10 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, leveraged or derivative securities, options, direct real estate investments, precious metals, venture capital and limited partnerships. 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, 2005 and 2004, and weighted average targeted asset allocation at December 31, 2005, were as follows:

							Weighted Average
	Percentage						Targeted Asset
	of Plan						Allocation
	Assets						Percentage
Asset Category	2005			2004			2005
Equity securities		70	%		70	%		70	%
Fixed income securities		28			28			30	*
Other		2			2			---
Total		100	%		100	%		100	%

* Includes target for both fixed income securities and other.

The Company expects to contribute approximately $1.2 million to its defined benefit pension plans and approximately $3.3 million to its postretirement benefit plans in 2006.

The following benefit payments, which reflect future service, as appropriate, are expected to be paid:

			Other
	Pension		Postretirement
Years	Benefits		Benefits
	(In thousands)
2006	$	13,118	$	4,172
2007		13,554		4,344
2008		14,130		4,478
2009		14,915		4,675
2010		15,899		4,897
2011-2015		95,429		27,848

The following Medicare Part D subsidies are expected: $288,000 in 2006; $589,000 in 2007; $620,000 in 2008; $650,000 in 2009; $682,000 in 2010; and $4.0 million during the years 2011 through 2015.

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 $39.6 million, $28.2 million and $27.2 million in 2005, 2004 and 2003, respectively.

In addition to the qualified plan defined pension benefits reflected in the table at the beginning of this note, the Company also has an unfunded, nonqualified benefit plan for executive officers and certain key management employees that generally provides for defined benefit payments at age 65 following the employee's retirement or to their beneficiaries upon death for a 15-year period. Investments, at December 31, 2005, consisted of cash equivalents, fixed income securities, equity securities, and life insurance carried on plan participants, which is payable to the Company upon the employee's death. The Company's net periodic benefit cost for this plan was $7.4 million, $7.5 million and $5.3 million in 2005, 2004 and 2003, respectively. The total projected obligation for this plan was $64.9 million and $65.3 million at December 31, 2005 and 2004, respectively. The accumulated benefit obligation for this plan was $55.0 million and $52.3 million at December 31, 2005 and 2004, respectively. The additional minimum liability relating to this plan was $11.6 million and $14.3 million at December 31, 2005 and 2004, respectively. The Company had no related intangible asset as of December 31, 2005, and had a related intangible asset recognized as of December 31, 2004, of $851,000. A discount rate of 5.50 percent and 5.75 percent at December 31, 2005 and 2004, respectively, and a rate of compensation increase of 4.25 percent and 4.75 percent at December 31, 2005 and 2004, respectively, were used to determine benefit obligations.

A discount rate of 5.75 percent and 6.00 percent at December 31, 2005 and 2004, respectively, and a rate of compensation increase of 4.75 percent at both December 31, 2005 and 2004, were used to determine net periodic benefit cost. The decrease in minimum liability included in other comprehensive income was $1.1 million in 2005 and the increase in minimum liability in other comprehensive income was $3.8 million in 2004.

The amount of benefit payments for the unfunded, nonqualified benefit plan, as appropriate, are expected to aggregate $2.6 million in 2006; $2.9 million in 2007; $3.1 million in 2008; $3.3 million in 2009; $3.5 million in 2010; and $21.4 million for the years 2011 through 2015.

The Company sponsors various defined contribution pension plans for eligible employees. Costs incurred by the Company under these plans were $17.0 million in 2005, $13.8 million in 2004 and $9.8 million in 2003. The costs incurred in each year reflect additional participants as a result of business acquisitions.

NOTE 16 - JOINTLY OWNED FACILITIES

The consolidated financial statements include the Company's 22.7 percent and 25.0 percent ownership interests in the assets, liabilities and expenses of the Big Stone Station and the Coyote Station, respectively. Each owner of the Big Stone and Coyote stations is responsible for 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:

	2005		2004
	(In thousands)
Big Stone Station:
Utility plant in service	$	56,305	$	52,157
Less accumulated depreciation		38,011		36,488
	$	18,294	$	15,669
Coyote Station:
Utility plant in service	$	125,007	$	124,388
Less accumulated depreciation		76,563		74,671
	$	48,444	$	49,717

NOTE 17 - REGULATORY MATTERS AND REVENUES SUBJECT TO REFUND

On September 30, 2005, Montana-Dakota filed an application with the MTPSC for a natural gas rate increase. Montana-Dakota requested a total increase of $1.1 million annually or 1.3 percent above current rates. On January 26, 2006, this application was withdrawn as a result of Montana-Dakota’s implementation of cost-reduction measures.

In September 2004, Great Plains filed an application with the MPUC for a natural gas rate increase. Great Plains had requested a total increase of $1.4 million annually or approximately 4.0 percent above current rates. Great Plains also requested an interim increase of $1.4 million annually. In November 2004, the MPUC issued an Order authorizing an interim increase of $1.4 million annually effective with service rendered on or after January 10, 2005, subject to refund. A final order from the MPUC is expected in early 2006.

A liability has been provided for a portion of the revenues that have been collected subject to refund with respect to Great Plains’ pending regulatory proceeding. Great Plains believes that the liability is adequate based on its assessment of the ultimate outcome of the proceeding.

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. On April 19, 2005, the FERC issued its Order on Compliance Filing and Motion for Refunds. In this Order, the FERC approved Williston Basin’s refund rates and established rates to be effective April 19, 2005. Williston Basin filed its compliance filing complying with the requirements of this Order regarding rates and issued refunds totaling approximately $18.5 million to its customers on May 19, 2005. As a result of the Order, Williston Basin recorded a $5.0 million (after tax) benefit from the resolution of the rate proceeding which included the reversal of a portion of the liability it had previously established for this regulatory proceeding. On June 16, 2005, Williston Basin appealed to the D.C. Appeals Court certain issues addressed by the FERC’s Order on Initial Decision dated July 2003 and its Order on Rehearing dated May 2004 concerning determinations associated with cost of service and volumes used in allocating costs and designing rates. Those matters are pending resolution by the D.C. Appeals Court. A provision has been established for certain issues pending before the D.C. Appeals Court. The Company believes that the provision is adequate based on its assessment of the ultimate outcome of the proceeding.

In May 2004, the FERC remanded issues regarding certain service and annual demand quantity restrictions to an ALJ for resolution. Williston Basin participated in a hearing before the ALJ in early January 2005, regarding those service and annual demand quantity restrictions. On April 8, 2005, the ALJ issued an Initial Decision on the matters remanded by the FERC. In the Initial Decision, the ALJ decided that Williston Basin had not supported its position regarding the service and annual demand quantity restrictions. Williston Basin filed its Brief on Exceptions regarding these issues with the FERC on May 9, 2005, and its Brief Opposing Exceptions to issues raised by a certain party to the proceeding on May 31, 2005. On November 22, 2005, the FERC issued an Order on Initial Decision affirming the ALJ’s Initial Decision regarding the service and annual demand quantity restrictions. On December 22, 2005, Williston Basin filed its Request for Rehearing of the FERC’s Order on Initial Decision. This matter is awaiting resolution by the FERC.

NOTE 18 - COMMITMENTS AND CONTINGENCIES

Litigation

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.

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

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, 2005, were $13.2 million in 2006, $8.6 million in 2007, $6.5 million in 2008, $4.2 million in 2009, $2.8 million in 2010 and $24.1 million thereafter. Rent expense was $34.0 million, $30.6 million and $27.2 million for the years ended December 31, 2005, 2004 and 2003, 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, 2005, were $303.6 million in 2006, $131.3 million in 2007, $79.5 million in 2008, $63.5 million in 2009, $62.7 million in 2010 and $294.4 million thereafter. Amounts purchased under various commitments for the years ended December 31, 2005, 2004 and 2003, were approximately $443.9 million, $318.3 million and $204.6 million, respectively. These commitments are not reflected in the Company’s consolidated financial statements.

In addition to the above obligations, the Company has certain purchase obligations for natural gas connected to its gathering system. These purchases and the resale of the natural gas are at market-based prices. These obligations continue as long as natural gas is produced. However, if the purchase and resale of natural gas become uneconomical, the purchase commitments can be canceled by the Company with 60 days notice. These purchase obligations are estimated at approximately $10 million annually.

Guarantees

In addition, WBI Holdings has guaranteed certain of Fidelity's natural gas and oil price swap and collar agreement obligations. Fidelity's obligations at December 31, 2005, were $16.3 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, 2005, expire in 2006; however, Fidelity 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. The amount outstanding by Fidelity was reflected on the Consolidated Balance Sheets at December 31, 2005. In the event Fidelity 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. These guarantees are related to natural gas transportation and sales agreements, electric power supply agreements and certain other guarantees. At December 31, 2005, the fixed maximum amounts guaranteed under these agreements aggregated $73.6 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $8.5 million in 2006; $10.3 million in 2007; $400,000 in 2008; $900,000 in 2009; $30.0 million in 2010; $12.0 million in 2012; $2.0 million in 2028; $500,000, which is subject to expiration 30 days after the receipt of written notice; and $9.0 million, which has no scheduled maturity date. A guarantee for an unfixed amount estimated at $250,000 at December 31, 2005, has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $532,000 and was reflected on the Consolidated Balance Sheets at December 31, 2005. 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.

Centennial has outstanding letters of credit to third parties related to insurance policies and other agreements that guarantee the performance of other subsidiaries of the Company. At December 31, 2005, the fixed maximum amounts guaranteed under these letters of credit aggregated $32.3 million. The letters of credit are scheduled to expire in 2006. There were no amounts outstanding under the above letters of credit at December 31, 2005.

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. At December 31, 2005, 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 2008 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 $1.7 million, which was not reflected on the Consolidated Balance Sheets at December 31, 2005, because these intercompany transactions are eliminated in consolidation.

In addition, Centennial has issued guarantees to third parties related to the Company’s routine purchase of maintenance items and lease obligations 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 or lease obligations, Centennial would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these maintenance items and lease obligations were reflected on the Consolidated Balance Sheets at December 31, 2005.

As of December 31, 2005, Centennial was contingently liable for the performance of certain of its subsidiaries under approximately $454 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 is 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.

NOTE 19 - RELATED PARTY TRANSACTIONS

In 2004, Bitter Creek entered into two natural gas gathering agreements with Nance Petroleum. Robert L. Nance, an executive officer and shareholder of St. Mary, also is a member of the Board of Directors of the Company. The natural gas gathering agreements with Nance Petroleum were effective upon completion of certain high and low pressure gathering facilities, which occurred in mid-December 2004. Bitter Creek's capital expenditures related to the completion of the gathering lines and the expansion of its gathering facilities to accommodate the natural gas gathering agreements were $2.5 million and $7.6 million in 2005 and 2004, respectively, and are estimated for the next three years to be $2.2 million in 2006, $3.3 million in 2007 and $500,000 in 2008. The natural gas gathering agreements are each for a term of 15 years and month-to-month thereafter. Bitter Creek's revenues from these contracts were $1.2 million and $37,000 in 2005 and 2004, respectively, and estimated revenues from these contracts for the next three years are $2.8 million in 2006, $3.5 million in 2007 and $5.4 million in 2008. The amount due from Nance Petroleum at December 31, 2005, was $118,000.

In 2005, Montana-Dakota entered into agreements to purchase natural gas from Nance Petroleum through March 31, 2006. Montana-Dakota’s expenses under these agreements were $4.2 million in 2005. Montana-Dakota estimates that it will purchase approximately $2.2 million of natural gas from Nance Petroleum in 2006. The amount due to Nance Petroleum at December 31, 2005, was $686,000.

In 2005, Fidelity entered into an agreement for the purchase of an ownership interest in a natural gas and oil property with a third party whereunder it became a party to a joint operating agreement in which St. Mary is the operator of the property. St. Mary receives an overhead fee as operator of this property. The Company recorded its proportionate share of capital costs allocable to its ownership interest in the related property, which were not material to Fidelity.

SUPPLEMENTARY FINANCIAL INFORMATION

Quarterly Data (Unaudited)

The following unaudited information shows selected items by quarter for the years 2005 and 2004:

First

Second

Third

Fourth

Quarter

(In thousands, except per share amounts)

2005

Operating revenues

604,295

770,172

1,066,862

1,014,085

Operating expenses

539,182

656,648

917,267

894,291

Operating income

65,113

113,524

149,595

119,794

Net income

34,420

80,173

87,223

73,267

Earnings per common share:

Basic

.29

.68

.73

.61

Diluted

.29

.67

.72

.61

Weighted average common shares

outstanding:

Basic

117,827

118,348

119,619

119,815

Diluted

118,773

119,037

120,389

120,642

2004
Operating revenues	$	515,459	$	653,301	$	804,598	$	745,899
Operating expenses		471,436		568,570		690,022		668,511
Operating income		44,023		84,731		114,576		77,388
Net income		23,580		58,630		71,719		53,138
Earnings per common share:
Basic		.20		.50		.61		.45
Diluted		.20		.50		.60		.45
Weighted average common shares
outstanding:
Basic		114,658		116,559		117,109		117,582
Diluted		115,709		117,567		118,278		118,596

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 and Mid-Continent regions 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, Texas 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, the Powder River Basin of Montana and Wyoming, and the Tabasco and Texan Gardens fields in Texas.

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:

	2005		2004		2003
	(In thousands)
Subject to amortization	$	1,198,669	$	904,620	$	758,500
Not subject to amortization		82,291		68,984		104,339
Total capitalized costs		1,280,960		973,604		862,839
Less accumulated depreciation,
depletion and amortization		456,554		373,932		305,349
Net capitalized costs	$	824,406	$	599,672	$	557,490

Capital expenditures, including those not subject to amortization, related to natural gas and oil producing activities were as follows:

Years ended December 31,	2005*		2004*		2003*
	(In thousands)
Acquisitions:
Proved properties	$	149,253	$	188	$	1,664
Unproved properties		16,920		11,031		1,363
Exploration		24,385		21,781		19,193
Development**		125,633		77,940		77,583
Total capital expenditures	$	316,191	$	110,940	$	99,803

* Excludes net 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 8, of $2.5 million, $100,000 and $14.7 million for the years ended December 31, 2005, 2004 and 2003, respectively.

** Includes expenditures for proved undeveloped reserves of $37.0 million, $30.3 million and $23.3 million for the years ended December 31, 2005, 2004 and 2003, 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,	2005		2004		2003
	(In thousands)
Revenues:
Sales to affiliates	$	275,828	$	190,354	$	124,077
Sales to external customers		159,390		149,660		140,034
Production costs		88,068		67,125		67,292
Depreciation, depletion and
amortization*		84,099		69,946		60,072
Pretax income		263,051		202,943		136,747
Income tax expense		99,071		73,137		51,925
Results of operations for
producing activities before
cumulative effect of accounting
change		163,980		129,806		84,822
Cumulative effect of accounting
change		---		---		(7,740	)
Results of operations for
producing activities	$	163,980	$	129,806	$	77,082

* Includes accretion of discount for asset retirement obligations of $1.5 million for the year ended December 31, 2005, and $1.4

million for each of the years ended December 31, 2004 and 2003, in accordance with SFAS No. 143, as discussed in Note 8.

The following table summarizes the Company's estimated quantities of proved natural gas and oil reserves at December 31, 2005, 2004 and 2003, 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.

	2005						2004						2003
	Natural						Natural						Natural
	Gas			Oil			Gas			Oil			Gas			Oil
				(MMcf/MBbls)
Proved developed and
undeveloped reserves:
Balance at beginning of year		453,200			17,100			411,700			18,900			372,500			17,500
Production		(59,400	)		(1,700	)		(59,700	)		(1,800	)		(54,700	)		(1,900	)
Extensions and discoveries		74,400			500			100,700			500			113,300			3,300
Improved recovery		---			2,600			---			---			---			---
Purchases of proved reserves		57,400			3,700			100			---			900			---
Sales of reserves in place		(1,300	)		(100	)		---			---			---			(100	)
Revisions of previous estimates		(35,200	)		(900	)		400			(500	)		(20,300	)		100
Balance at end of year		489,100			21,200			453,200			17,100			411,700			18,900

Proved developed reserves:

January 1, 2003	331,300	14,800
December 31, 2003	342,800	15,000
December 31, 2004	376,400	16,400
December 31, 2005	416,700	20,400

The Company's interests in natural gas and oil reserves are located primarily 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:

	2005		2004		2003
	(In thousands)
Future cash inflows	$	4,778,700	$	2,848,800	$	2,547,400
Future production costs		1,095,400		803,600		651,300
Future development costs		106,400		62,800		67,100
Future net cash flows before income taxes		3,576,900		1,982,400		1,829,000
Future income tax expense		1,205,700		645,300		601,000
Future net cash flows		2,371,200		1,337,100		1,228,000
10% annual discount for estimated timing of
cash flows		950,400		515,600		491,200
Discounted future net cash flows relating to
proved natural gas and oil reserves	$	1,420,800	$	821,500	$	736,800

The following are the sources of change in the standardized measure of discounted future net cash flows by year:

	2005			2004			2003
	(In thousands)
Beginning of year	$	821,500		$	736,800		$	506,300
Net revenues from production		(402,900	)		(291,600	)		(220,000	)
Change in net realization		777,700			32,800			318,600
Extensions and discoveries, net of future
production-related costs		294,800			240,200			245,800
Improved recovery, net of future production-related costs		91,600			---			---
Purchases of proved reserves, net of future production-related costs		258,300			300			2,800
Sales of reserves in place		(12,500	)		---			(600	)
Changes in estimated future development costs		(13,400	)		(5,300	)		(4,000	)
Development costs incurred during the current year		40,900			39,800			35,300
Accretion of discount		106,900			97,100			62,400
Net change in income taxes		(339,700	)		(36,400	)		(172,000	)
Revisions of previous estimates		(200,500	)		9,600			(35,500	)
Other		(1,900	)		(1,800	)		(2,300	)
Net change		599,300			84,700			230,500
End of year	$	1,420,800		$	821,500		$	736,800

The estimated discounted future cash inflows from estimated future production of proved reserves were computed using year-end natural gas 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 as of December 31, 2005, are $70.7 million in 2006, $6.0 million in 2007 and none in 2008. 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 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.

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.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The information required by this item is included in this Form 10-K at Item 8 - Financial Statements and Supplementary Data - Management’s Report on Internal Control over Financial Reporting.

ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM

The information required by this item is included in this Form 10-K at Item 8 - Financial Statements and Supplementary Data - Report of Independent Registered Public Accounting Firm.

ITEM 9B. OTHER INFORMATION

None.

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," "Section 16(a) Beneficial Ownership Reporting Compliance," "Board and Board Committees" and "Nominating and Governance Committee" in the 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 "Approval of the Amended and Restated 1997 Executive Long-Term Incentive 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 AND FINANCIAL STATEMENT SCHEDULES

(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, 2005

Consolidated Balance Sheets at December 31, 2005 and 2004

Consolidated Statements of Common Stockholders’ Equity for each of the three years in the period ended December 31, 2005

Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2005

Notes to Consolidated Financial Statements

2. Financial Statement Schedules

MDU Resources Group, Inc.

Schedule II - Consolidated Valuation and Qualifying Accounts

Years Ended December 31, 2005, 2004 and 2003

Additions

Balance at

Charged to

Balance

Beginning

Costs and

at End

Description

of Year

Expenses

Other*

Deductions**

of Year

(In thousands)

Allowance for doubtful accounts:

2005

6,801

4,870

1,675

5,315

8,031

2004

8,146

2,663

703

4,711

6,801

2003

8,237

3,185

1,123

4,399

8,146

* Allowance for doubtful accounts for companies acquired and recoveries.

** 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)	Company Bylaws, as amended, filed as Exhibit 3(a) to Form 10-Q for the quarter ended September 30, 2005, 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, filed as Exhibit 4(e) to Form 10-K for the year ended December 31, 2003, in File No. 1-3480*

4(f)	Centennial Energy Holdings, Inc. Master Shelf Agreement, dated April 29, 2005, among Centennial Energy Holdings, Inc. and The Prudential Insurance Company of America, filed as Exhibit 4(a) to Form 10-Q for the quarter ended June 30, 2005, in File No. 1-3480*

4(g)	MDU Resources Group, Inc. Credit Agreement, dated June 21, 2005, among MDU Resources Group, Inc., Wells Fargo Bank, National Association, as Administrative Agent, and The Other Financial Institutions Party thereto, filed as Exhibit 4(b) to Form 10-Q for the quarter ended June 30, 2005, in File No. 1-3480*

4(h)	Centennial Energy Holdings, Inc. Credit Agreement, dated August 26, 2005, among Centennial Energy Holdings, Inc., U.S. Bank National Association, as Administrative Agent, and The Other Financial Institutions party thereto, filed as Exhibit 4(a) to Form 10-Q for the quarter ended September 30, 2005, in File No. 1-3480*

+10(a)	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(b)	Supplemental Income Security Plan, as amended and restated February 17, 2005, filed as Exhibit 10(a) to Form 10-Q for the quarter ended March 31, 2005, in File No. 1-3480*

+10(c)	Directors' Compensation Policy, as amended on May 12, 2005, filed as Exhibit 10(e) to Form 10-Q for the quarter ended June 30, 2005, in File No. 1-3480*

+10(d)	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(e)	Non-Employee Director Stock Compensation Plan, as amended, filed as Exhibit 10(h) to Form 10-Q for the quarter ended June 30, 2004, in File No. 1-3480*

+10(f)	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(g)	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(h)	Change of Control Employment Agreement between the Company and Paul Gatzemeier, filed as Exhibit 10(a) to Form 10-Q for the quarter ended June 30, 2004, in File No. 1-3480*

+10(i)	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(j)	Change of Control Employment Agreement between the Company and Bruce T. Imsdahl, filed as Exhibit 10(c) to Form 10-Q for the quarter ended June 30, 2004, in File No. 1-3480*

+10(k)	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(l)	Change of Control Employment Agreement between the Company and Cindy C. Redding, filed as Exhibit 10(d) to Form 10-Q for the quarter ended June 30, 2004, in File No. 1-3480*

+10(m)	Change of Control Employment Agreement between the Company and Paul K. Sandness, filed as Exhibit 10(e) to Form 10-Q for the quarter ended June 30, 2004, in File No. 1-3480*

+10(n)	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(o)	Change of Control Employment Agreement between the Company and Daryl A. Splichal, filed as Exhibit 10(f) to Form 10-Q for the quarter ended June 30, 2004, in File No. 1-3480*

+10(p)	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(q)	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(r)	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(s)	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(t)	The Wagner-Smith Company Deferred Compensation Plan, filed as Exhibit 10(w) to Form 10-K for the year ended December 31, 2003, in File No. 1-3480*

+10(u)	Wagner-Smith Equipment Co. Deferred Compensation Plan, filed as Exhibit 10(x) to Form 10-K for the year ended December 31, 2003, in File No. 1-3480*

+10(v)	The Bauerly Brothers, Inc. Deferred Compensation Plan, filed as Exhibit 10(aa) to Form 10-K for the year ended December 31, 2003, in File No. 1-3480*

+10(w)	The Oregon Electric Construction, Inc. Deferred Compensation Plan, filed as Exhibit 10(ab) to Form 10-K for the year ended December 31, 2003, in File No. 1-3480*

10(x)	Purchase and Sale Agreement between Fidelity and Smith Production Inc., dated April 19, 2005 (Flores), filed as Exhibit 10(a) to Form 10-Q for the quarter ended June 30, 2005, in File No. 1-3480*

10(y)	Purchase and Sale Agreement between Fidelity and Smith Production Inc., dated April 19, 2005 (Tabasco and Texan Gardens), filed as Exhibit 10(b) to Form 10-Q for the quarter ended June 30, 2005, in File No. 1-3480*

10(z)	First Amendment to the Purchase and Sale Agreements between Fidelity and Smith Production Inc., dated April 19, 2005, filed as Exhibit 10(c) to Form 10-Q for the quarter ended June 30, 2005, in File No. 1-3480*

10(aa)	Second Amendment to the Purchase and Sale Agreement between Fidelity and Smith Production Inc., dated April 19, 2005, filed as Exhibit 10(d) to Form 10-Q for the quarter ended June 30, 2005, in File No. 1-3480*

+10(ab)	MDU Resources Group, Inc. 2006 NEO Base Compensation Table, filed as Exhibit 10.1 to Form 8-K dated November 17, 2005, in File No. 1-3480*

+10(ac)	WBI Holdings, Inc. Executive Incentive Compensation Plan, filed as Exhibit 10.4 to Form 8-K dated February 17, 2005, in File No. 1-3480*

+10(ad)	Knife River Corporation Executive Incentive Compensation Plan, filed as Exhibit 10.5 to Form 8-K dated February 17, 2005, in File No. 1-3480*

+10(ae)	1997 Executive Long-Term Incentive Plan, as amended November 17, 2005**

+10(af)	MDU Resources Group, Inc. Executive Incentive Compensation Plan, as amended November 17, 2005**

+10(ag)	Montana-Dakota Utilities Co. Executive Incentive Compensation Plan, as amended November 17, 2005**

+10(ah)	Agreement on Retirement, dated November 23, 2005, between the Company and Warren L. Robinson**

+10(ai)	Change of Control Employment Agreement between the Company and Steven L. Bietz**

+10(aj)	Change of Control Employment Agreement between the Company and Nicole A. Kivisto**

+10(ak)	Change of Control Employment Agreement between the Company and Doran N. Schwartz**

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	Consent of Independent Registered Public Accounting Firm**

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.

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 22, 2006	By:	/s/ Martin A. White
			Martin A. White (Chairman of the Board 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 Officer and Director	February 22, 2006
Martin A. White (Chairman of the Board and Chief Executive Officer)

/s/ Terry D. Hildestad	President and Chief Operating Officer	February 22, 2006
Terry D. Hildestad (President and Chief Operating Officer)

/s/ Vernon A. Raile	Chief Financial Officer	February 22, 2006
Vernon A. Raile (Executive Vice President and Chief Financial Officer)

/s/ Daniel B. Moylan	Chief Accounting Officer	February 22, 2006
Daniel B. Moylan (Chief Accounting Officer)

/s/ Harry J. Pearce	Lead Director	February 22, 2006
Harry J. Pearce

/s/ Thomas Everist	Director	February 22, 2006
Thomas Everist

/s/ Karen B. Fagg	Director	February 22, 2006
Karen B. Fagg

/s/ Dennis W. Johnson	Director	February 22, 2006
Dennis W. Johnson

/s/ Richard H. Lewis	Director	February 22, 2006
Richard H. Lewis

/s/ Patricia L. Moss	Director	February 22, 2006
Patricia L. Moss

/s/ Robert L. Nance	Director	February 22, 2006
Robert L. Nance

/s/ John L. Olson	Director	February 22, 2006
John L. Olson

/s/ Sister Thomas Welder	Director	February 22, 2006
Sister Thomas Welder

/s/ John K. Wilson	Director	February 22, 2006
John K. Wilson

Mdu Resources Group Inc – ‘10-K’ for 12/31/05

On: Wednesday, 2/22/06, at 1:40pm ET · For: 12/31/05 · Accession #: 67716-6-58 · File #: 1-03480

Previous ‘10-K’: ‘10-K’ on 2/23/05 for 12/31/04 · Next: ‘10-K’ on 2/21/07 for 12/31/06 · Latest: ‘10-K’ on 2/22/24 for 12/31/23

Annual Report — Form 10-K
Filing Table of Contents

10-K — Mdu Resources Group, Inc. 2005 10-K

This is an HTML Document rendered as filed. [ Alternative Formats ]

Dates Referenced Herein and Documents Incorporated by Reference

This ‘10-K’ Filing	Date	Other Filings

	12/15/33
	12/31/20
	7/1/19
	12/31/16
	12/1/13
	4/1/12
	8/26/10
	12/31/08	10-K, 11-K, 4, 8-K
	10/31/08	8-K
	3/31/08	10-Q, 4, 8-K
	12/20/07
	4/30/07	4
	4/1/07
	1/1/07
	12/31/06	10-K, 10-K/A, 11-K
	10/31/06
	5/31/06
	3/31/06	10-Q, 4, DEFA14A
Filed on:	2/22/06	4
	2/15/06
	2/14/06
	1/27/06	8-K
	1/26/06
	1/1/06
For Period End:	12/31/05	11-K, 5
	12/23/05
	12/22/05
	12/16/05
	12/9/05
	11/30/05	4, 8-K
	11/23/05	4
	11/22/05	4, 8-K
	11/17/05	3
	11/1/05
	10/1/05
	9/30/05	10-Q, 4
	9/2/05
	8/26/05	4, 8-K
	8/10/05
	6/30/05	10-Q, 4, 8-K
	6/21/05
	6/16/05	11-K
	6/6/05
	5/31/05	4, 8-K
	5/19/05	4, 8-K
	5/13/05	4
	5/12/05	4
	5/9/05
	4/29/05	4, 8-K
	4/19/05	8-K
	4/8/05
	3/31/05	10-Q, 4, 8-K
	2/17/05	4, 8-K
	1/10/05
	1/1/05
	12/31/04	10-K, 11-K, 4, 5, 8-K
	7/1/04	4
	6/30/04	10-Q, 4, 8-K
	1/21/04	8-A12B/A, S-8
	12/31/03	10-K, 11-K, 4, 4/A, 5, 8-K
	12/15/03
	10/29/03
	10/10/03
	8/14/03
	6/13/03	S-3/A
	1/1/03
	12/31/02	10-K, 11-K, 8-K
	9/30/02	10-Q
	12/31/01	10-K, 11-K, 424B2, 8-K
	4/30/01
	6/30/00	10-Q
	6/1/00
	11/12/98	10-Q, 8-A12B, 8-K
	4/21/92
		List all Filings

Mdu Resources Group Inc – ‘10-K’ for 12/31/05

On: Wednesday, 2/22/06, at 1:40pm ET · For: 12/31/05 · Accession #: 67716-6-58 · File #: 1-03480

Previous ‘10-K’: ‘10-K’ on 2/23/05 for 12/31/04 · Next: ‘10-K’ on 2/21/07 for 12/31/06 · Latest: ‘10-K’ on 2/22/24 for 12/31/23

Annual Report — Form 10-KFiling Table of Contents

10-K — Mdu Resources Group, Inc. 2005 10-K

This is an HTML Document rendered as filed. [ Alternative Formats ]

Dates Referenced Herein and Documents Incorporated by Reference

Annual Report — Form 10-K
Filing Table of Contents