Edgar Filing: MDU RESOURCES GROUP INC

MDU Resources 2006 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

X	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
	THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

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

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 Nox.

State the aggregate market value of the voting common stock held by nonaffiliates of the registrant as of June 30, 2006: $4,393,239,107.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of February 12, 2007: 181,147,966 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s 2007 Proxy Statement are incorporated by reference in Part III, Items 10, 11, 12, 13 and 14 of this Report.

CONTENTS

PART I

Forward-Looking Statements

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, Executive Officers and Corporate Governance

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, and Director Independence

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
Alusa	Tecnica de Engenharia Electrica - Alusa
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
Big Stone Station	450-MW coal-fired electric generating facility located near Big Stone City, South Dakota (22.7 percent ownership)
Bitter Creek	Bitter Creek Pipelines, LLC, an indirect wholly owned subsidiary of WBI Holdings
Black Hills Power	Black Hills Power and Light Company
BLM	Bureau of Land Management
Brascan	Brascan Brasil Ltda.
Brazilian Transmission Lines	Company’s equity method investment in companies owning ECTE, ENTE and ERTE
Brush Generating Facility	213 MW of natural gas-fired electric generating facilities near Brush, Colorado
Btu	British thermal units
Carib Power	Carib Power Management LLC
Cascade	Cascade Natural Gas Corporation
CBNG	Coalbed natural gas
CELESC	Centrais Elétricas de Santa Catarina S.A.
CEM	Colorado Energy Management, LLC, a direct wholly owned subsidiary of Centennial Resources
CEMIG	Companhia Energética de Minas Gerais - CEMIG
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
Colorado Federal District Court	U.S. District Court for the District of Colorado
Company	MDU Resources Group, Inc.
D.C. Appeals Court	U.S. Court of Appeals for the District of Columbia Circuit
dk	Decatherm
DRC	Dakota Resource Council
EBSR	Elk Basin Storage Reservoir, one of Williston Basin’s natural gas storage reservoirs, which is located in Montana and Wyoming
ECTE	Empresa Catarinense de Transmissão de Energia S.A.
EITF	Emerging Issues Task Force
EITF No. 00-21	Revenue Arrangements with Multiple Deliverables
EITF No. 04-6	Accounting for Stripping Costs in the Mining Industry
EITF No. 91-6	Revenue Recognition of Long-Term Power Sales Contracts
EIS	Environmental Impact Statement
ENTE	Empresa Norte de Transmissão de Energia S.A.
EPA	U.S. Environmental Protection Agency
ERTE	Empresa Regional de Transmissão de Energia S.A.
ESA	Endangered Species Act
Exchange Act	Securities Exchange Act of 1934, as amended
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
FIN 48	Accounting for Uncertainty in Income Taxes
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
Hart-Scott-Rodino Act	Hart-Scott-Rodino Antitrust Improvements Act, as amended
Hartwell	Hartwell Energy Limited Partnership
Hartwell Generating Facility	310-MW natural gas-fired electric generating facility near Hartwell, Georgia (50 percent ownership)
Hobbs Power	Hobbs Power Funding, LLC, an indirect subsidiary of ArcLight Energy Partners Fund III, L.P.
Howell	Howell Petroleum Corporation, a wholly owned subsidiary of Anadarko
IBEW	International Brotherhood of Electrical Workers

Indenture	Indenture dated as of December 15, 2003, as supplemented, from the Company to The Bank of New York as Trustee
Innovatum	Innovatum, Inc., a former indirect wholly owned subsidiary of WBI Holdings (the stock and a portion of Innovatum’s assets were sold during the fourth quarter of 2006)
Item 8	Financial Statements and Supplementary Data
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
LPP	Lea Power Partners, LLC, a former direct wholly owned subsidiary of Centennial Power (member interests were sold in October 2006)
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., 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
MNPUC	Minnesota Public Utilities Commission
Montana-Dakota	Montana-Dakota Utilities Co., a public utility division of the Company
Montana DEQ	Montana State Department of Environmental Quality
Montana Federal District Court	U.S. District Court for the District of Montana
Mortgage	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
MPX	MPX Termoceara Ltda. (49 percent ownership, sold in June 2005)
MTPSC	Montana Public Service Commission
MW	Megawatt
Nance Petroleum	Nance Petroleum Corporation, a wholly owned subsidiary of St. Mary
ND Health Department	North Dakota Department of Health
NDPSC	North Dakota Public Service Commission
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
Oregon DEQ	Oregon State Department of Environmental Quality
PCBs	Polychlorinated biphenyls
PPA	Power purchase and sale agreement
Prairielands	Prairielands Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI Holdings
Proxy Statement	Company’s 2007 Proxy Statement
PSCo	Public Service Company of Colorado, a wholly owned subsidiary of Xcel Energy
RCRA	Resource Conservation and Recovery Act
SAFETEA-LU	Safe, Accountable, Flexible and Efficient Transportation Equity Act - A Legacy for Users
San Joaquin	San Joaquin Cogen, LLC, a direct wholly owned subsidiary of Centennial Power
San Joaquin Generating Facility	48-MW natural gas-fired electric generating facility near Lathrop, California
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. 144	Accounting for the Impairment or Disposal of Long-Lived Assets
SFAS No. 148	Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123
SFAS No. 157	Fair Value Measurements
SFAS No. 158	Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans
Sheridan System	A separate electric system owned by Montana-Dakota
SIP	State Implementation Act
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, owned and operated by MPX
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
TRWUA	Tongue River Water Users’ Association
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

FORWARD-LOOKING STATEMENTS

This Form 10-K contains forward-looking statements within the meaning of Section 21E of the Exchange Act. 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, and 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.

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. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.

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 (comprised of the pipeline and energy services and the natural gas and oil production segments), Knife River (construction materials and mining segment), MDU Construction Services (construction services segment), Centennial Resources (independent power production segment) and Centennial Capital (reflected in the Other category).

As of December 31, 2006, the Company had 11,526 employees with 161 employed at MDU Resources Group, Inc., 885 at Montana-Dakota, 35 at Great Plains, 539 at WBI Holdings, 5,032 at Knife River, 4,715 at MDU Construction Services and 159 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, 426 and 73 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 1,000 of its construction materials employees. Knife River is in negotiations on nine of its labor contracts.

MDU Construction Services has 82 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 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 - Note 15 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 and in Item 8 - Note 20. 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 Exchange Act 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 119,000 residential, commercial, industrial and municipal customers located in 177 communities and adjacent rural areas as of December 31, 2006. 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, 2006, Montana-Dakota's net electric plant investment approximated $319.8 million.

Substantially all of Montana-Dakota's electric properties are subject to the lien of the Mortgage and to the junior lien of the Indenture.

The percentage of Montana-Dakota's 2006 retail electric utility operating revenues by jurisdiction is as follows: North Dakota - 60 percent; Montana - 22 percent; South Dakota - 7 percent; and Wyoming - 11 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 also are 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 participates in the Midwest ISO wholesale energy market.

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. As a member of Midwest ISO, Montana-Dakota’s generation is sold into the Midwest ISO energy market and its energy needs are purchased from that 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 478,270 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. 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 also will be purchased as needed from the Midwest ISO market.

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

				2006 Net
		Nameplate	Summer	Generation
		Rating	Capability	(kWh in
Generating Station	Type	(kW)	(kW)	thousands)

North Dakota:
Coyote*	Steam	103,647	106,750	701,413
Heskett	Steam	86,000	102,870	444,266
Williston	Combustion Turbine	7,800	9,600	(66)	**
South Dakota:
Big Stone*	Steam	94,111	104,550	727,347
Montana:
Lewis & Clark	Steam	44,000	52,300	336,936
Glendive	Combustion Turbine	77,347	79,400	6,514
Miles City	Combustion Turbine	23,150	22,800	1,649
		436,055	478,270	2,218,059

* Reflects Montana-Dakota's ownership interest.

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

Virtually all of the current fuel requirements of the Coyote, Heskett and Lewis & Clark stations are met with coal supplied by subsidiaries of Westmoreland. Contracts with Westmoreland for the Coyote, Heskett and Lewis & Clark stations expire in May 2016, April 2011 and December 2007, respectively. 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 of 1.3 million tons of coal in 2007. The Arch agreement provides for the purchase of 500,000 tons of coal in 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 Heskett coal supply agreement provides for the purchase of coal necessary to supply the coal requirements of Heskett Station at contracted pricing. Montana-Dakota estimates the coal requirement to be in the range of 500,000 to 600,000 tons per contract year. 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, 2004, through December 31, 2006, 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,		2006		2005		2004
Average cost of coal per million Btu	$	1.26	$	1.14	$	1.08
Average cost of coal per ton	$	18.48	$	17.01	$	15.96

The maximum electric peak demand experienced to date attributable to sales to retail customers on the interconnected system was 485,456 kW in July 2006. 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 2012 will approximate 1.2 percent annually.

Montana-Dakota expects that it has adequate capacity available through existing baseload generating stations, turbine peaking stations and firm contracts to meet the peak demand requirements of its customers through 2012. Future capacity that is needed to replace contracts and meet system growth requirements is expected to be met by constructing new generation resources or acquiring additional capacity 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 56,400 kW and occurred in July 2006.

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 Power to serve the Sheridan load.

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. An Electric Power Supply Cost Adjustment mechanism approved by the WYPSC in December 2006 will allow Montana-Dakota to timely reflect increases or decreases in fuel and purchased power costs related to the power supply contract with Black Hills Power mentioned above. In Montana, which in 2006 accounted for 22 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.

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. One permit was renewed in 2006. The next permit will expire in 2009. State water discharge permits issued under the requirements of the Clean Water Act are maintained for power production facilities on the Yellowstone and Missouri rivers. These permits also have five-year lives. Montana-Dakota renews these permits as necessary prior to expiration. Other permits held by these facilities may include an initial siting permit, which is typically a one-time, preconstruction permit issued by the state; state permits to dispose of combustion by-products; state authorizations to withdraw water for operations; and 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.

On November 20, 2006, the Sierra Club sent a notice of intent to file a citizen suit in federal court under the Clean Air Act to the co-owners, including Montana-Dakota, of the Big Stone Station. For more information regarding this notice, see Item 8 - Note 20.

Montana-Dakota did not incur any material environmental expenditures in 2006. Expenditures are estimated to be $4.6 million, $16.3 million and $4.2 million in 2007, 2008 and 2009, respectively, to maintain environmental compliance as new emission controls are required. Projects will include sulfur-dioxide and mercury control equipment installation at the power plants. For matters involving Montana-Dakota and the ND Health Department, see Item 8 - Note 20.

NATURAL GAS DISTRIBUTION

General Montana-Dakota sells natural gas at retail, serving over 231,000 residential, commercial and industrial customers in 145 communities and adjacent rural areas as of December 31, 2006, 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 in 19 communities and adjacent rural areas as of December 31, 2006, 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 5,600 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, 2006, Montana-Dakota's and Great Plains' net natural gas distribution plant investment approximated $164.0 million.

Substantially all of Montana-Dakota's natural gas distribution properties are subject to the lien of the Mortgage and to the junior lien of the Indenture.

The percentage of Montana-Dakota's and Great Plains' 2006 natural gas utility operating revenues by jurisdiction is as follows: North Dakota - 39 percent; Minnesota - 11 percent; Montana - 24 percent; South Dakota - 20 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 MNPUC regarding retail rates, service, accounting and certain security issuances.

During 2006, the Company entered into a definitive merger agreement to acquire Cascade. For more information regarding Cascade, see Item 8 - Note 22.

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:

Years Ended December 31,	2006			2005			2004
	(Mdk)
Sales:
Residential		18,998			20,086			20,303
Commercial		13,830			14,457			14,598
Industrial		1,725			1,688			1,706
Total		34,553			36,231			36,607
Transportation:
Commercial		1,579			1,637			1,702
Industrial		12,479			12,928			12,154
Total		14,058			14,565			13,856
Total throughput		48,611			50,796			50,463
Degree days * (% of normal)		86.7	%		90.9	%		90.7	%

* 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 also has 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 In September 2004, Great Plains filed an application with the MNPUC for a natural gas rate increase. For additional information regarding Great Plains' natural gas rate increase filing, see Item 8 - Note 19.

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.

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 2006 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 2009.

Montana-Dakota commenced the remediation of a historic manufactured gas plant located in Bismarck, North Dakota, in early 2007. Expenses related to this work are not expected to be material and are expected to be recovered through the regulatory process. In addition, Montana-Dakota has had an economic interest in five other historic manufactured gas plants within its service territory, none of which are currently being actively investigated, and for which any remediation expenses are not expected to be material.

CONSTRUCTION SERVICES

General MDU Construction Services specializes in electrical line construction, pipeline construction, inside electrical wiring and cabling, external lighting and traffic signalization, and mechanical and fire protection services as well as the manufacture and distribution of specialty equipment. These services are provided to utilities and large manufacturing, commercial, government and institutional customers.

During 2006, the Company acquired a construction service business in Nevada. This acquisition was not 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, 2006, MDU Construction Services owned or leased offices in 16 states. This space is used for offices, equipment yards, warehousing, storage and vehicle shops. At December 31, 2006, MDU Construction Services’ net plant investment was approximately $45.8 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, 2006, was approximately $527 million compared to $403 million at December 31, 2005. MDU Construction Services expects to complete a significant amount of this backlog during the year ending December 31, 2007. 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 subcontract 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 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 2006 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2009.

PIPELINE AND ENERGY SERVICES

General Williston Basin, the 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 in the states of Montana, North Dakota, South Dakota and Wyoming. Three underground storage fields 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, 2006, Williston Basin’s net plant investment was approximately $235.5 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.

Bitter Creek, the nonregulated pipeline business, owns and operates gathering facilities in Colorado, Kansas, Montana and Wyoming. Bitter Creek also owns a one-sixth interest in the assets of various offshore gathering pipelines, an associated onshore pipeline and related processing facilities. In total, these facilities include over 1,800 miles of field gathering lines and 83 owned or leased compression facilities, some of which interconnect with Williston Basin’s system. In addition, Bitter Creek provides installation sales and/or leasing of alternate energy delivery systems, primarily propane air facilities, energy efficiency product sales and installation services to large end users.

WBI Holdings, through its energy services business, 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.

In 2006, WBI Holdings sold Innovatum, a cable and pipeline magnetization and locating company. Certain assets of Innovatum were not included in the sale; however, the Company is actively pursuing a sale of those remaining assets. For additional information regarding Innovatum, see Item 8 - Notes 2 and 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 certain of Williston Basin's firm customers, including its largest customer Montana-Dakota, serve relatively secure residential and commercial end users, they generally all have some price-sensitive end users that could switch to alternate fuels.

Williston Basin transports substantially all of Montana-Dakota's natural gas, primarily utilizing firm transportation agreements, which for the year ended December 31, 2006, represented 66 percent of Williston Basin's currently subscribed firm transportation contract demand. Montana-Dakota has a firm transportation agreement with Williston Basin for a term of five years expiring in June 2012. 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.

Bitter Creek competes with several pipelines for existing customers and expansions of its systems to gather natural gas in new areas. Bitter Creek’s strong position in the fields in which it operates, its focus on customer service, along with its interconnection with various other pipelines serve to enhance its competitive position.

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. For information regarding natural gas storage legal proceedings, see Item 1A - Risk Factors - Other Risks and Item 8 - Note 20.

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 CBNG assets in the Powder River Basin are expected to meet some of these supply needs. For additional information regarding CBNG legal proceedings, see Item 1A - Risk Factors - Environmental and Regulatory Risks and Item 8 - Note 20. 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, see Item 8 - Note 19.

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.

Ongoing operations 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 2006 and do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2009.

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 and leaseholds 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 primarily in three core regions: Rocky Mountain, Mid-Continent/ Gulf States and Offshore Gulf of Mexico.

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 Baker Field in southeastern Montana and southwestern North Dakota, the Bowdoin area located in north-central Montana, and the Powder River Basin of Montana and Wyoming. In 2006, Fidelity acquired and became the operator of natural gas and oil properties in the Big Horn Basin of Wyoming. This acquisition was not material to the Company. Fidelity also owns nonoperated natural gas and oil interests and undeveloped acreage positions in this region.

Mid-Continent/Gulf States

This region includes properties in Alabama, Louisiana, New Mexico, Oklahoma and Texas. 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 and undeveloped acreage positions 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.

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 Mcf equivalent for 2006, 2005 and 2004, were as follows:

	2006		2005		2004
Natural gas:
Production (MMcf)		62,062		59,378		59,750
Average realized price per Mcf (including hedges)	$	6.03	$	6.11	$	4.69
Average realized price per Mcf (excluding hedges)	$	5.62	$	6.87	$	4.90
Oil:
Production (MBbls)		2,041		1,707		1,747
Average realized price per barrel (including hedges)	$	50.64	$	42.59	$	34.16
Average realized price per barrel (excluding hedges)	$	51.73	$	48.73	$	37.75
Production costs, including taxes, per Mcf equivalent:
Lease operating costs	$	.71	$	.56	$	.47
Gathering and transportation		.25		.20		.17
Production and property taxes		.47		.50		.32
	$	1.43	$	1.26	$	.96

2006 annual net production by region was as follows:

	Natural
	Gas		Oil		Total		Percent of
Region	(MMcf)		(MBbls)		(MMcfe)		Total
Rocky Mountain		47,879		1,172		54,909		74	%
Mid-Continent/Gulf States		8,513		560		11,872		16
Offshore Gulf of Mexico		5,670		309		7,526		10
Total		62,062		2,041		74,307		100	%

Well and Acreage Information Gross and net productive well counts and gross and net developed and undeveloped acreage related to Fidelity’s interests at December 31, 2006, were as follows:

	Gross*		Net**
Productive wells:
Natural gas		4,128		3,373
Oil		3,817		240
Total		7,945		3,613
Developed acreage (000's)		749		377
Undeveloped acreage (000's)		963		399

* 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 2006, 2005 and 2004:

	Net Exploratory			Net Development
	Productive	Dry Holes	Total	Productive	Dry Holes	Total	Total
2006	4	1	5	331	1	332	337
2005	2	3	5	312	25	337	342
2004	1	4	5	230	20	250	255

At December 31, 2006, there were 222 gross (194 net) wells in the process of drilling or under evaluation, 215 of which were development wells and 7 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.

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, the Clean Air 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.

Detailed environmental assessments and/or environmental impact statements under federal and state laws are required as part of the permitting process incidental to the commencement of drilling and production operations as well as in the closure, abandonment and reclamation of facilities.

In connection with the development of CBNG properties, certain capital expenditures were incurred related to water handling. For 2006, capital expenditures for water handling in compliance with current laws and regulations were approximately $800,000 and are estimated to be approximately $3.3 million, $2.6 million and $1.8 million in 2007, 2008 and 2009, respectively. For more information regarding CBNG legal proceedings, see Item 1A - Risk Factors and Item 8 - Note 20.

Reserve Information Fidelity's recoverable proved developed and undeveloped natural gas and oil reserves by region at December 31, 2006, are as follows:

Region	Natural Gas (MMcf)		Oil (MBbls)		Total (MMcfe)		Percent of Total			PV-10 Value * (in millions)
Rocky Mountain		413,000		19,600		530,800		76	%	$	1,028.7
Mid-Continent/Gulf States		112,700		6,700		152,500		22			343.9
Offshore Gulf of Mexico		12,400		800		17,400		2			63.9
Total reserves		538,100		27,100		700,700		100	%	$	1,436.5

* 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 - 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 - 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, Washington and Wyoming. These operations mine, process and sell construction aggregates (crushed stone, sand and gravel); produce and sell asphalt and liquid asphalt for various commercial and roadway applications; and supply ready-mixed concrete for use in most types of construction, including roads, freeways and bridges as well as homes, schools, shopping centers, office buildings and industrial parks. 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 2006, the Company acquired construction materials and mining businesses with operations in California and Washington. None of these acquisitions was 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.

In August 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, Iowa will receive a 25 percent increase, Texas will receive a 37 percent increase and Washington will receive a 27 percent increase.

The construction materials business had approximately $483 million in backlog at December 31, 2006, compared to $465 million at December 31, 2005. The Company anticipates that a significant amount of the current backlog will be completed during the year ending December 31, 2007.

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, Description of Property by Issuers Engaged or to be Engaged in Significant Mining Opeartions. Remaining reserves are based on estimates of volumes that can be economically extracted and sold to meet current market and product applications. The reserve estimates include only salable tonnage and thus exclude waste materials that are generated in the crushing and processing phases of the operation. Approximately 1.1 billion tons of the 1.2 billion tons of aggregate reserves are permitted reserves. The remaining reserves are on properties that are expected to 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, 2006, and sales as of and for the years ended December 31, 2006, 2005 and 2004:

	Number of Sites		Number of Sites
	(Crushed Stone)		(Sand & Gravel)		Tons Sold (000's)			Estimated Reserves		Reserve
Production Area	owned	leased	owned	leased	2006	2005	2004	(000’s tons)	Lease Expiration	Life (years)
Central MN	---	1	52	57	4,834	4,608	6,429	105,666	2007-2028	22
Portland, OR	1	4	5	3	5,862	5,559	5,821	260,406	2007-2055	44
Northern CA	1	---	7	1	3,031	4,180	3,699	49,299	2046	16
Southwest OR	4	8	12	5	4,425	3,892	3,405	119,138	2007-2031	27
Eugene, OR	3	3	4	2	3,026	2,009	2,003	180,616	2007-2046	60
Hawaii	---	6	---	---	3,167	2,891	2,460	71,112	2011-2037	22
Central MT	---	---	5	1	2,619	2,408	2,555	42,492	2023	16
Anchorage, AK	---	---	1	---	1,142	1,307	1,473	20,830	N/A	18
Northwest MT	---	---	8	5	1,434	1,679	1,810	25,479	2007-2020	18
Southern CA	---	2	---	---	244	166	518	95,399	2035	Over 100
Bend, OR/WA/ Boise, ID	2	2	5	2	1,788	1,731	1,678	105,959	2010-2012	59
Northern MN	2	---	21	20	520	968	853	31,655	2007-2016	61
Northern IA/ Southern MN	18	10	8	26	2,024	2,063	1,370	66,883	2007-2017	33
North/South Dakota	---	---	2	59	1,157	1,205	965	54,060	2007-2031	47
Eastern TX	1	2	---	4	917	1,255	1,067	18,127	2007-2012	20
Casper, WY	---	---	---	1	5	2	291	978	2007	Over 100
Sales from other sources					9,405	11,281	7,047	---
					45,600	47,204	43,444	1,248,099

The 1.2 billion tons of estimated aggregate reserves at December 31, 2006, is comprised of 539 million tons that are owned and 709 million tons that are leased. The leases have various expiration dates ranging from 2007 to 2055. Approximately 49 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 20 years, including options for renewal that are at Knife River’s discretion. Based on 2006 sales from leased reserves, the average time necessary to produce remaining aggregate reserves from such leases is approximately 43 years.

The following table summarizes Knife River’s aggregate reserves at December 31, 2006, 2005 and 2004, and reconciles the changes between these dates:

	2006			2005			2004
	(000’s of tons)
Aggregate reserves:
Beginning of year		1,273,696			1,257,498			1,181,413
Acquisitions		7,300			53,495			115,965
Sales volumes*		(36,195	)		(35,923	)		(36,397	)
Other		3,298			(1,374	)		(3,483	)
End of year		1,248,099			1,273,696			1,257,498
* 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, 2006, Knife River had under ownership or lease, deposits of approximately 10.1 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 the management of hazardous wastes and underground storage tank systems. 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 wastes and underground storage tank systems.

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 mining operations or processing plants. 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 comprehensive 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.

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 2006 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 2009.

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, see Item 8 - Note 20.

INDEPENDENT POWER PRODUCTION

General Centennial Resources owns, builds and operates electric generating facilities in the United States and has investments in domestic and international transmission and 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. During the fourth quarter of 2006, the Company initiated a plan to sell certain of the domestic assets of Centennial Resources, which largely comprise the independent power production segment. For additional information regarding the potential sale, see Item 8 - Note 3.

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 capacity and energy is sold to PSCo. A PPA with PSCo for 130 MW expires in September 2012. In December 2005, Centennial Power entered into two successive PPAs with PSCo for the sale of 75 MW of capacity and energy. One PPA expires in April 2007 followed by a 10-year PPA 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 PPAs.

Centennial Power owns a 67-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 a PPA with the California Department of Water Resources, which expires in September 2011. AES Wind Generation operates the facility under a contract that expires in October 2013.

In April 2006, Centennial Power purchased the member interests of San Joaquin, which owns a 48-MW natural gas-fired electric generating facility near Lathrop, California. The facility sells all of its capacity and energy under a PPA with Southern California Edison Company that expires in December 2010. CEM operates the San Joaquin generating station. Southern California Edison Company will supply and be responsible for all fuel, fuel transportation and fuel balancing for the San Joaquin generating station during the term of the PPA.

Centennial Power has a 50-percent ownership interest in 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 PPA 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 owns a 116-MW coal-fired electric generating facility near Hardin, Montana. The Hardin Generating Facility began operations in early 2006. A PPA 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 Powerex 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 Centennial Power having an option of a two-year extension. CEM operates the Hardin Generating Facility.

In October 2006, Centennial Power sold 100 percent of its membership interests in LPP to Hobbs Power. Centennial Power formed LPP to develop a 550-MW natural gas-fired electric generating facility to be built near Hobbs, New Mexico. CEM will construct the facility. CEM also is in negotiations to operate the facility. Onsite construction is expected to begin by the spring of 2007 with plant operations scheduled to commence the summer of 2008. Revenues associated with the sale are expected to be recognized over the period of construction of the new facility.

CEM provides analysis, design, construction, refurbishment, and operation and maintenance services related to electric generating facilities. CEM is headquartered in Lafayette, Colorado, and was acquired in April 2004. In addition to operating the Brush, Hardin and San Joaquin facilities, CEM provides operation and maintenance services for third-party customers owning approximately 510 MW of generating capacity. The operation and maintenance contracts related to these third-party customers have expirations ranging from July 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, Hardin Generating Facility and San Joaquin 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 two Title V Operating Permits, each 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 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 Hardin Generating Facility is operating under an air quality permit issued by the state of Montana. 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 California state spill prevention and control regulations. The San Joaquin Generating Facility has a Title V Operating Permit issued by the regional air district in California for a period of five years under a program approved by the EPA. The facility also has waste water discharge agreements with the cities of Lathrop and Manteca, which are issued for one-year and three-year periods, respectively.

Centennial Power’s operations did not incur any material environmental expenditures in 2006 and do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2009.

International

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 PPA expires in September 2029. T&TEC also is under contract to supply natural gas to the Trinity Generating Facility during the term of the PPA. On December 29, 2006, the Company entered into an agreement to sell its interest in Carib Power. Closing is expected to occur in the first quarter of 2007.

On August 16, 2006, MDU Brasil acquired ownership interests in companies owning three electric transmission lines. The interests involve the ENTE (13.3-percent ownership interest), ERTE (13.3-percent ownership interest) and ECTE (25-percent ownership interest) electric transmission lines, which are primarily in northeastern and southern Brazil. The transmission contracts provide for revenues denominated in the Brazilian Real, annual inflation adjustments and change in tax law adjustments and have between 24 and 26 years remaining under the contracts. Alusa, Brascan and CEMIG hold the remaining ownership interests, with CELESC also having an ownership interest in ECTE. Alusa is the operating partner for the transmission lines. The functional currency for the Brazilian Transmission Lines is the Brazilian Real.

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 - Note 4. In November 2005, the joint venture relationship was terminated.

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 2006 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2009.

ITEM 1A. RISK FACTORS

The Company’s business and financial results are subject to a number of risks and uncertainties, including those set forth below and in other documents that it files with the SEC. The 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 and service 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.

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 CBNG 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 CBNG development activities. These proceedings have caused delays in CBNG drilling activity, and the ultimate outcome of the actions could have a material negative effect on existing CBNG operations and/or the future development of its CBNG 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 CBNG 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 negative effect on Fidelity's existing CBNG operations and/or the future development of its CBNG properties.

The BER in March 2006 issued a decision in a rulemaking proceeding, initiated by the NPRC, that amends the non-degradation policy applicable to water discharged in connection with CBNG operations. The amended policy includes additional limitations on factors deemed harmful, thereby restricting water discharges even further than under previous standards. Due in part to this amended policy, in May 2006, the Northern Cheyenne Tribe commenced litigation in Montana state court challenging two five-year water discharge permits that the Montana DEQ granted to Fidelity in February 2006 and which are critical to Fidelity’s ability to manage water produced under present and future CBNG operations. If these permits are set aside, Fidelity’s CBNG operations in Montana could be significantly and adversely affected.

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 foreign operations may diminish due to political, regulatory and economic conditions and changes in currency exchange rates in countries where the Company does business.

The Company is subject to political, regulatory and economic conditions and changes in currency exchange rates in foreign countries where the Company does business. Significant changes in the political, regulatory or economic environment in these countries could negatively affect the value of the Company’s investments located in these countries. Also since the Company is unable to predict the fluctuations in the foreign currency exchange rates, these fluctuations may have an adverse impact on the Company’s results of operations.

Other Risks

The Company’s pending acquisition of Cascade may be delayed or may not occur if certain conditions are not satisfied. Upon completion of the acquisition, if the Company is unable to integrate the Cascade operations effectively, its future financial position or results of operations may be adversely affected.

The Company has entered into a definitive merger agreement to acquire Cascade. The total value of the transaction, including the assumption of certain indebtedness, is approximately $475 million. The completion of the acquisition is subject to the approval of various regulatory authorities and the satisfaction of other customary closing conditions. The Company’s pending acquisition of Cascade may be delayed or may not occur if the Company is unable to timely obtain necessary regulatory approvals, satisfy closing conditions or obtain financing. If the Company is unable to integrate the Cascade operations effectively, its future financial position or results of operations may be adversely affected.

One of the Company’s subsidiaries is engaged in litigation with a nonaffiliated natural gas producer that has been conducting drilling and production operations that the subsidiary believes is causing diversion and loss of quantities of storage gas from one of its storage reservoirs. If the subsidiary is not able to obtain relief through the courts or the regulatory process, its storage operations could be materially and adversely affected.

Williston Basin has filed suit in Federal court in Montana seeking to recover unspecified damages from Anadarko and its wholly owned subsidiary, Howell, and to enjoin Anadarko and Howell’s present and future production operations in and near the EBSR. Based on relevant information, including reservoir and well pressure data, Williston Basin believes that EBSR pressures have decreased and that the storage reservoir has lost gas and continues to lose gas as a result of Anadarko and Howell’s drilling and production activities. In related litigation, Howell filed suit in Wyoming state district court against Williston Basin asserting that it is entitled to produce any gas that might escape from Williston Basin’s storage reservoir. Williston Basin has answered Howell’s complaint and has asserted counterclaims. Williston Basin has sought preliminary injunctive relief seeking to enjoin the subject Anadarko and Howell wells from taking Williston Basin’s storage gas. If Williston Basin is unable to obtain timely relief through the courts or regulatory process, its present and future gas storage operations, including its ability to meet its contractual storage and transportation obligations to customers, could be materially and adversely affected.

Weather conditions can adversely affect the Company’s operations and revenues.

The Company’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas, affect the wind-powered operation at the independent power production business, affect the price of energy commodities, affect the ability to perform services at the 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. 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 also are 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 independent power production industry has many competitors in the operation, acquisition and development of power generation facilities. 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

Increases in employee and retiree benefit costs

ITEM 1B. UNRESOLVED COMMENTS

The Company has no unresolved comments with the SEC.

ITEM 3. LEGAL PROCEEDINGS

For information regarding legal proceedings of the Company, see Item 8 - Note 20.

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 2006.

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 under the symbol "MDU." The price range of the Company's common stock as reported by The Wall Street Journal composite tape during 2006 and 2005 and dividends declared thereon were as follows:

			Common
	Common	Common	Stock
	Stock Price	Stock Price	Dividends
	(High)	(Low)	Per Share
2006
First quarter	$24.53	$21.85	$.1267
Second quarter	24.99	22.53	.1267
Third quarter	25.40	22.25	.1350
Fourth quarter	27.04	22.29	.1350
			$.5234

2005
First quarter	$19.00	$16.99	$.1200
Second quarter	19.56	17.57	.1200
Third quarter	24.05	18.72	.1267
Fourth quarter	24.75	20.57	.1267
			$.4934

Note: Common stock share amounts reflect the Company’s three-for-two common stock split effected in July 2006.

As of December 31, 2006, the Company's common stock was held by approximately 15,400 stockholders of record.

ITEM 6. SELECTED FINANCIAL DATA

Operating Statistics	2006			2005			2004			2003			2002			2001
Selected Financial Data
Operating revenues (000's):
Electric	$	187,301		$	181,238		$	178,803		$	178,562		$	162,616		$	168,837
Natural gas distribution		351,988			384,199			316,120			274,608			186,569			255,389
Construction services		987,582			687,125			426,821			434,177			458,660			364,750
Pipeline and energy services		443,720			477,311			354,164			250,897			163,466			528,262
Natural gas and oil production		483,952			439,367			342,840			264,358			203,595			209,831
Construction materials and mining		1,877,021			1,604,610			1,322,161			1,104,408			962,312			806,899
Independent power production		66,145			48,508			43,059			32,261			2,998			---
Other		8,117			6,038			4,423			2,728			3,778			---
Intersegment eliminations		(335,142	)		(375,965	)		(272,199	)		(191,105	)		(114,249	)		(113,188	)
	$	4,070,684		$	3,452,431		$	2,716,192		$	2,350,894		$	2,029,745		$	2,220,780
Operating income (000's):
Electric	$	27,716		$	29,038		$	26,776		$	35,761		$	33,915		$	38,731
Natural gas distribution		8,744			7,404			1,820			6,502			2,414			3,576
Construction services		50,651			28,171			(5,757	)		12,885			13,980			25,199
Pipeline and energy services		57,133			43,507			29,570			37,064			40,118			30,255
Natural gas and oil production		231,802			230,383			178,897			118,347			85,555			103,943
Construction materials and mining		156,104			105,318			86,030			91,579			91,430			71,451
Independent power production		(510	)		4,916			8,126			10,610			(1,176	)		---
Other		596			420			136			1,233			908			---
	$	532,236		$	449,157		$	325,598		$	313,981		$	267,144		$	273,155
Earnings on common stock (000's):
Electric	$	14,401		$	13,940		$	12,790		$	16,950		$	15,780		$	18,717
Natural gas distribution		5,680			3,515			2,182			3,869			3,587			677
Construction services		27,851			14,558			(5,650	)		6,170			6,371			12,910
Pipeline and energy services		32,126			22,867			13,806			19,852			20,099			16,768
Natural gas and oil production		145,657			141,625			110,779			70,767			53,192			63,178
Construction materials and mining		85,702			55,040			50,707			54,261			48,702			43,199
Independent power production		4,513			22,921			26,309			11,415			307			---
Other		1,302			707			321			606			652			---
Earnings on common stock before
loss from discontinued operations
and cumulative effect of accounting change		317,232			275,173			211,244			183,890			148,690			155,449
Loss from discontinued operations,
net of tax		(2,160	)		(775	)		(4,862	)		(1,694	)		(1,002	)		(362	)
Cumulative effect of accounting change		---			---			---			(7,589	)		---			---
	$	315,072		$	274,398		$	206,382		$	174,607		$	147,688		$	155,087

Earnings per common share before
discontinued operations and cumulative effect of accounting change - diluted	$	1.75		$	1.53	$	1.20		$	1.09		$	.93		$	1.02
Discontinued operations, net of tax		(.01	)		---		(.03	)		(.01	)		(.01	)		---
Cumulative effect of accounting change		---			---		---			(.04	)		---			---
	$	1.74		$	1.53	$	1.17		$	1.04		$	.92		$	1.02

Common Stock Statistics
Weighted average common shares
outstanding - diluted (000's)		181,392		179,490		176,117		168,690		160,295		152,705
Dividends per common share	$	.5234	$	.4934	$	.4667	$	.4400	$	.4177	$	.4000
Book value per common share	$	11.88	$	10.43	$	9.39	$	8.44	$	7.71	$	7.07
Market price per common share (year end)	$	25.64	$	21.83	$	17.79	$	15.87	$	11.47	$	12.51

Market price ratios:
Dividend payout	30%	32%	40%	43%	45%	39%
Yield	2.1%	2.3%	2.7%	2.9%	3.7%	3.3%
Price/earnings ratio	14.7x	14.3x	15.2x	15.4x	12.5x	12.3x
Market value as a percent of book value	215.8%	209.2%	189.4%	188.1%	148.8%	177.0%
Profitability Indicators
Return on average common equity	15.6%	15.7%	13.2%	13.0%	12.5%	15.3%
Return on average invested capital	10.6%	10.8%	9.4%	8.9%	8.6%	10.1%
First mortgage bond interest coverage	26.0x	10.2x	7.1x	7.4x	7.7x	8.5x
Fixed charges coverage, including
preferred dividends	6.3x	6.1x	4.7x	4.7x	4.8x	5.3x

General
Total assets (000's)	$	4,903,474	$	4,423,562	$	3,733,521	$	3,380,592	$	2,996,921	$	2,675,978
Long-term debt, net of current maturities (000's)	$	1,170,548	$	1,104,752	$	873,441	$	939,450	$	819,558	$	783,709
Redeemable preferred stock (000's)	$	---	$	---	$	---	$	---	$	1,300	$	1,400

Capitalization ratios:
Common equity	65%	63%	65%	60%	60%	58%
Preferred stocks	---	---	1	1	1	1
Long-term debt, net of current maturities	35	37	34	39	39	41
	100%	100%	100%	100%	100%	100%

NOTE: Common stock share amounts reflect the Company’s three-for-two common stock splits effected in July 2006 and October 2003.

Operating Statistics	2006			2005			2004			2003			2002			2001
Electric
Retail sales (thousand kWh)		2,483,248			2,413,704			2,303,460			2,359,888			2,275,024			2,177,886
Sales for resale (thousand kWh)		483,944			615,220			821,516			841,637			784,530			898,178
Electric system summer generating and firm purchase capability - kW (Interconnected system)		547,485			546,085			544,220			542,680			500,570			500,820
Demand peak - kW
(Interconnected system)		485,456			470,470			470,470			470,470			458,800			453,000
Electricity produced (thousand kWh)		2,218,059			2,327,228			2,552,873			2,384,884			2,316,980			2,469,573
Electricity purchased (thousand kWh)		833,647			892,113			794,829			929,439			857,720			792,641
Average cost of fuel and
purchased power per kWh	$	.022		$	.020		$	.019		$	.019		$	.018		$	.018
Natural Gas Distribution
Sales (Mdk)		34,553			36,231			36,607			38,572			39,558			36,479
Transportation (Mdk)		14,058			14,565			13,856			13,903			13,721			14,338
Weighted average degree days - % of previous
year's actual		95	%		100	%		94	%		96	%		109	%		95	%
Pipeline and Energy Services
Transportation (Mdk)		130,889			104,909			114,206			90,239			99,890			97,199
Gathering (Mdk)		87,135			82,111			80,527			75,861			72,692			61,136
Natural Gas and Oil Production
Production:
Natural gas (MMcf)		62,062			59,378			59,750			54,727			48,239			40,591
Oil (MBbls)		2,041			1,707			1,747			1,856			1,968			2,042
Average realized prices (including hedges):
Natural gas (per Mcf)	$	6.03		$	6.11		$	4.69		$	3.90		$	2.72		$	3.78
Oil (per barrel)	$	50.64		$	42.59		$	34.16		$	27.25		$	22.80		$	24.59
Proved reserves:
Natural gas (MMcf)		538,100			489,100			453,200			411,700			372,500			324,100
Oil (MBbls)		27,100			21,200			17,100			18,900			17,500			17,500
Construction Materials and Mining
Construction materials (000's):