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<SEC-DOCUMENT>0000067716-02-000023.txt : 20020415
<SEC-HEADER>0000067716-02-000023.hdr.sgml : 20020415
ACCESSION NUMBER:		0000067716-02-000023
CONFORMED SUBMISSION TYPE:	10-K
PUBLIC DOCUMENT COUNT:		9
CONFORMED PERIOD OF REPORT:	20011231
FILED AS OF DATE:		20020301

FILER:

	COMPANY DATA:	
		COMPANY CONFORMED NAME:			MDU RESOURCES GROUP INC
		CENTRAL INDEX KEY:			0000067716
		STANDARD INDUSTRIAL CLASSIFICATION:	GAS & OTHER SERVICES COMBINED [4932]
		IRS NUMBER:				410423660
		STATE OF INCORPORATION:			DE
		FISCAL YEAR END:			1231

	FILING VALUES:
		FORM TYPE:		10-K
		SEC ACT:		1934 Act
		SEC FILE NUMBER:	001-03480
		FILM NUMBER:		02564275

	BUSINESS ADDRESS:	
		STREET 1:		918 EAST DIVIDE AVENUE
		CITY:			BISMARCK
		STATE:			ND
		ZIP:			58506-5650
		BUSINESS PHONE:		7012227900

	MAIL ADDRESS:	
		STREET 1:		918 EAST DIVIDE AVENUE
		CITY:			BISMARCK
		STATE:			ND
		ZIP:			58506-5650

	FORMER COMPANY:	
		FORMER CONFORMED NAME:	MONTANA DAKOTA UTILITIES CO
		DATE OF NAME CHANGE:	19850429
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>mdu10k.txt
<DESCRIPTION>FORM 10-K
<TEXT>



           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, 2001

                                  OR

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

       For the transition period from ______________ to ____________

                    Commission file number 1-3480

                      MDU Resources Group, Inc.
        (Exact name of registrant as specified in its charter)

           Delaware                           41-0423660
 (State or other jurisdiction of  (I.R.S. Employer Identification No.)
  incorporation or organization)

                          Schuchart Building
                        918 East Divide Avenue
                             P.O. Box 5650
                   Bismarck, North Dakota 58506-5650
               (Address of principal executive offices)
                              (Zip Code)

                            (701) 222-7900
         (Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

     Title of each class              Name of each exchange
    Common Stock, par value $1.00      on which registered
and Preference Share Purchase Rights  New York Stock Exchange
                                      Pacific Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

                   Preferred Stock, par value $100
                           (Title of Class)

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

  Indicate  by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of the Registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K.

  State the aggregate market value of the voting stock held by
nonaffiliates of the registrant as of February 22, 2002:
$1,970,449,000.

  Indicate the number of shares outstanding of each of the
Registrant's classes of common stock, as of February 22, 2002:
69,874,062 shares.

DOCUMENTS INCORPORATED BY REFERENCE.
 1. Pages 32 through 63 of the Registrant's Annual Report to
    Stockholders for 2001 are incorporated by reference in Part  II,
    Items 6, 8 and 9 of this Report.
 2. Portions of the Registrant's Proxy Statement, dated March 8, 2002
    are incorporated by reference in Part III, Items 10, 11 and 12 of
    this Report.

                            CONTENTS

PART I

 Items 1 and 2 -- Business and Properties
   General
   Electric
   Natural Gas Distribution
   Utility Services
   Pipeline and Energy Services
   Natural Gas and Oil Production
   Construction Materials and Mining --
     Construction Materials
     Coal
     Consolidated Construction Materials and Mining

 Item 3 --  Legal Proceedings

 Item 4 --  Submission of Matters to a Vote of
             Security Holders

PART II

 Item 5 --  Market for the Registrant's Common Stock and
             Related Stockholder Matters

 Item 6 --  Selected Financial Data

 Item 7 --  Management's Discussion and Analysis of
             Financial Condition and Results of
             Operations

 Item 7A -- Quantitative and Qualitative Disclosures About
             Market Risk

 Item 8 --  Financial Statements and Supplementary Data

 Item 9 --  Change in and Disagreements with Accountants
             on Accounting and Financial Disclosure

PART III

 Item 10 -- Directors and Executive Officers of the
             Registrant

 Item 11 -- Executive Compensation

 Item 12 -- Security Ownership of Certain Beneficial
             Owners and Management

 Item 13 -- Certain Relationships and Related
             Transactions

PART IV

 Item 14 -- Exhibits, Financial Statement Schedules and
             Reports on Form 8-K


                             PART I

    This Form 10-K contains forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
Forward-looking statements should be read with the cautionary
statements and important factors included in this Form 10-K at
Item 7 -- Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Safe Harbor for Forward-
looking Statements.  Forward-looking statements are all
statements other than statements of historical fact, including
without limitation, those statements that are identified by the
words "anticipates," "estimates," "expects," "intends," "plans,"
"predicts" and similar expressions.

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

GENERAL

    MDU Resources Group, Inc. (company) is a diversified natural
resource company which was incorporated under the laws of the
State of Delaware in 1924.  Its principal executive offices are
at the Schuchart Building, 918 East Divide Avenue, P.O. Box 5650,
Bismarck, North Dakota 58506-5650, telephone (701) 222-7900.

    Montana-Dakota Utilities Co. (Montana-Dakota), a public
utility division of the company, through the electric and natural
gas distribution segments, generates, transmits and distributes
electricity and distributes natural gas in the northern Great
Plains.  Great Plains Natural Gas Co. (Great Plains), another
public utility division of the company, distributes natural gas
in southeastern North Dakota and western Minnesota.  These
operations also supply related value-added products and services.

    The company, through its wholly owned subsidiary, Centennial
Energy Holdings, Inc. (Centennial), owns WBI Holdings, Inc. (WBI
Holdings), Knife River Corporation (Knife River), Utility
Services, Inc. (Utility Services) and Centennial Holdings Capital
Corp. (Centennial Capital).

    WBI Holdings is comprised of the pipeline and energy
    services and the natural gas and oil production
    segments.  The pipeline and energy services segment
    provides natural gas transportation, underground storage
    and gathering services through regulated and
    nonregulated pipeline systems primarily in the Rocky
    Mountain and northern Great Plains regions of the United
    States and provides energy-related marketing and
    management services, as well as cable and pipeline
    locating services.  The natural gas and oil production
    segment is engaged in natural gas and oil acquisition,
    exploration and production activities primarily in the
    Rocky Mountain region of the United States and in the
    Gulf of Mexico.

    Knife River mines aggregates and markets crushed stone,
    sand, gravel and other related construction materials,
    including ready-mixed concrete, cement and asphalt, as
    well as value-added products and services in the north
    central and western United States, including Alaska and
    Hawaii.

    Utility Services is a diversified infrastructure company
    specializing in engineering, design and build capability
    for electric, gas and telecommunication utility
    construction, as well as industrial and commercial
    electrical, exterior lighting and traffic signalization
    throughout most of the United States.  Utility Services
    also provides related specialty equipment manufacturing,
    sales and rental services.

    Centennial Capital invests in new growth and synergistic
    opportunities, including independent power production,
    which are not directly being pursued by the existing
    business units but which are consistent with the
    company's philosophy and growth strategy.  These
    activities are reflected in the pipeline and energy
    services segment.

    The company, through its wholly owned subsidiary, MDU
Resources International, Inc. (MDU International), invests in
projects outside the United States which are consistent with the
company's philosophy, growth strategy and areas of expertise.
These activities are reflected in the pipeline and energy
services segment.

    On August 30, 2001, MDU International through an indirect
wholly owned Brazilian subsidiary, entered into a joint venture
agreement with a Brazilian firm under which the parties have
formed MPX Holdings, Ltda. (MPX) to develop electric generation
and transmission, steam generation, power equipment, coal mining
and construction materials projects in Brazil.  MDU International
has a 49 percent interest in MPX.  MPX is currently developing,
through a wholly owned subsidiary, and has under construction a
200-megawatt natural gas-fired power plant (Project) in the
Brazilian state of Ceara.   The Project is expected to enter
commercial operation in the second quarter of 2002.  MPX expects
to enter into an agreement with Petrobras, the state-controlled
energy company, under which Petrobras would purchase all of the
capacity and market all of the Project's energy.  Petrobras would
also supply natural gas to the Project when energy is dispatched.
The Project has a total estimated construction cost of
approximately $96 million.  At December 31, 2001, MDU
International's investment in the Project was approximately $23.8
million.  In addition, the company's subsidiaries had guaranteed
Project obligations and loans for approximately $17.3 million as
of December 31, 2001.

    On February 5, 2002, Centennial Power, Inc., an indirect
wholly owned subsidiary of the company, announced the acquisition
of Rocky Mountain Power, Inc.  The acquisition enables the
company to construct a 113-megawatt, coal-fired electric
generation facility (Plant) near Hardin, Montana. The Plant is
expected to enter commercial operation in 2003.  The Plant will
provide electricity to Montana Power, LLC through a long-term
power purchase agreement.  Centennial Power, Inc. expects to
enter into a coal supply agreement to supply coal to the Plant.

    As of December 31, 2001, the company had 6,568 full-time
employees with 90 employed at MDU Resources Group, Inc., 885 at
Montana-Dakota, 59 at Great Plains, 424 at WBI Holdings, 2,501 at
Knife River's operations and 2,609 at Utility Services.  The
number of employees at certain company operations fluctuates
during the year depending upon the number and size of
construction projects.  At Montana-Dakota and WBI Holdings, 426
and 67 employees, respectively, are represented by the
International Brotherhood of Electrical Workers (IBEW).  Labor
contracts with such employees are in effect through April 30,
2003 and March 31, 2002, for Montana-Dakota and WBI Holdings,
respectively.  WBI is currently negotiating a new labor contract
with the IBEW.  Knife River has 26 labor contracts which
represent 598 of its construction materials employees.  Utility
Services has 77 labor contracts representing the majority of its
employees.  The company considers its relations with employees to
be satisfactory.

    The company's principal properties, which are of varying ages
and are of different construction types are believed to be
generally in good condition, are well maintained, and are
generally suitable and adequate for the purposes for which they
are used.

    The financial results and data applicable to each of the
company's business segments as well as their financing
requirements are set forth in Item 7 -- Management's Discussion
and Analysis of Financial Condition and Results of Operations and
Notes to the Consolidated Financial Statements.

    Any reference to the company's Consolidated Financial
Statements and Notes thereto shall be to pages 33 through 61 in
the company's Annual Report to Stockholders for 2001 (Annual
Report), which are incorporated by reference herein.

ELECTRIC

General --

    Montana-Dakota provides electric service at retail, serving
over 115,000 residential, commercial, industrial and municipal
customers located in 177 communities and adjacent rural areas as
of December 31, 2001.  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
4,000 miles of transmission and distribution lines, respectively.
Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric operations in
all of the municipalities it serves where such franchises are
required.  For additional information regarding Montana-Dakota's
franchises, see Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of Operations.  As of
December 31, 2001, Montana-Dakota's net electric plant investment
approximated $266.2 million.

    All of Montana-Dakota's electric properties, with certain
exceptions, are subject to the lien of the Indenture of Mortgage
dated May 1, 1939, as supplemented, amended and restated, from
the company to The Bank of New York and Douglas J. MacInnes,
successor trustees.

    The electric operations of Montana-Dakota are subject to
regulation by the Federal Energy Regulatory Commission (FERC)
under provisions of the Federal Power Act with respect to the
transmission and sale of power at wholesale in interstate
commerce, interconnections with other utilities, the issuance of
securities, accounting and other matters.  Retail rates, service,
accounting and, in certain instances, security issuances are also
subject to regulation by the North Dakota Public Service
Commission (NDPSC), Montana Public Service Commission (MTPSC),
South Dakota Public Utilities Commission (SDPUC) and Wyoming
Public Service Commission (WYPSC).  The percentage of
Montana-Dakota's 2001 electric utility operating revenues by
jurisdiction is as follows:  North Dakota -- 61 percent;
Montana -- 23 percent; South Dakota -- 7 percent and
Wyoming -- 9 percent.

System Supply and System Demand --

    Through an interconnected electric system, Montana-Dakota
serves markets in portions of the following states and major
communities -- western North Dakota, including Bismarck,
Dickinson and Williston; eastern Montana, including Glendive and
Miles City; and northern South Dakota, including Mobridge.  The
interconnected system consists of seven on-line electric
generating stations which have an aggregate turbine nameplate
rating attributable to Montana-Dakota's interest of 393,488
Kilowatts (kW) and a total summer net capability of 434,420 kW.
Montana-Dakota's four principal generating stations are steam-
turbine generating units using coal for fuel.  The nameplate
rating for Montana-Dakota's ownership interest in these four
stations (including interests in the Big Stone Station and the
Coyote Station aggregating 22.7 percent and 25.0 percent,
respectively) is 327,758 kW.  The balance of Montana-Dakota's
interconnected system electric generating capability is supplied
by three combustion turbine peaking stations.  Additionally,
Montana-Dakota has contracted to purchase through October 31,
2006, 66,400 kW of participation power annually from Basin
Electric Power Cooperative for its interconnected system.

    The following table sets forth details applicable to the
company's electric generating stations:
                                                     2001 Net
                                                    Generation
                            Nameplate    Summer     (kilowatt-
 Generating                  Rating    Capability    hours in
  Station         Type        (kW)        (kW)      thousands)

North Dakota --
  Coyote*       Steam         103,647     106,750     783,635
  Heskett       Steam          86,000     104,330     584,211
  Williston     Combustion
                 Turbine        7,800       9,600         (28)**
South Dakota --
  Big Stone*    Steam          94,111     103,540     780,328

Montana --
  Lewis & Clark Steam          44,000      52,300     311,898
  Glendive      Combustion
                  Turbine      34,780      33,500       7,369
  Miles City    Combustion
                  Turbine      23,150      24,400       2,160

                              393,488     434,420   2,469,573

*  Reflects Montana-Dakota's ownership interest.
** Station use, to meet Mid-Continent Area Power Pool'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
Westmoreland Coal Company (Westmoreland).  Contracts with
Westmoreland for the Coyote, Heskett and Lewis & Clark stations
expire in May 2016, December 2005, and December 2002,
respectively.  The majority of the Big Stone Station's fuel
requirements are currently being met with coal supplied by RAG
Coal West, Inc. under contract through December 31, 2004.

    During the years ended December 31, 1997, through
December 31, 2001, the average cost of coal purchased, including
freight, per million British thermal units (Btu) at
Montana-Dakota's electric generating stations (including the Big
Stone and Coyote stations) in the interconnected system and the
average cost per ton, including freight, of the coal purchased
was as follows:

                                Years Ended December 31,
                       2001    2000      1999      1998     1997
Average cost of
  coal per
  million Btu          $.92    $.94      $.90      $.93     $.95
Average cost of
  coal per ton       $13.43  $13.68    $13.31    $13.67   $14.22

    The maximum electric peak demand experienced to date
attributable to sales to retail customers on the interconnected
system was 453,000 kW in August 2001.  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 2007 will approximate 1.1 percent annually.
Montana-Dakota's latest forecast indicates that its kilowatt-hour
(kWh) sales growth rate, on a normalized basis, through 2007 will
approximate 0.7 percent annually.

    Montana-Dakota currently estimates that, with modifications
already made and those expected to be made, it has adequate
capacity available through existing generating stations and long-
term firm purchase contracts until the year 2004.  If additional
capacity is needed in 2004 or after, it is expected to be met
through the addition of a 40-megawatt gas turbine power plant and
intermediate-term purchases.  In addition, the company and
Westmoreland Power, Inc. are working with the state of North
Dakota to determine the feasibility of constructing a 500-
megawatt lignite-fired power plant in western North Dakota.

    Montana-Dakota has major interconnections with its
neighboring utilities, all of which are Mid-Continent Area Power
Pool members.  Montana-Dakota considers these interconnections
adequate for coordinated planning, emergency assistance, exchange
of capacity and energy and power supply reliability.

    Through a separate electric system (Sheridan System), Montana-
Dakota serves Sheridan, Wyoming and neighboring communities.  The
maximum peak demand experienced to date and attributable to
Montana-Dakota sales to retail consumers on that system was
approximately 48,000 kW and occurred in August 2001.

    The Sheridan System is supplied through an interconnection
with Black Hills Power and Light Company under a power supply
contract through December 31, 2006 which allows for the purchase
of up to 55,000 kW of capacity annually.

Regulation and Competition --

    The electric utility industry can be expected to continue to
become increasingly competitive due to a variety of regulatory,
economic and technological changes.  The FERC, in its Order No.
888, has required that utilities provide open access and
comparable transmission service to third parties.  In addition,
as a result of competition in electric generation, wholesale
power markets have become increasingly competitive and
evaluations are ongoing concerning retail competition.

    Montana-Dakota joined the Midwest Independent Transmission
System Operator, Inc., (Midwest ISO) on September 4, 2001.  The
Midwest ISO, which the FERC accepted as a Regional Transmission
Organization (RTO) under FERC Order No. 2000 in an order issued
December 20, 2001, will be responsible for operational control of
the transmission systems of its members.  Thereafter, on December
26, 2001, Montana-Dakota filed an application with the FERC for
authorization to transfer operational control over certain of its
transmission facilities to the Midwest ISO, and, by order dated
January 29, 2002, the FERC authorized the transfer.  On December
31, 2001, the Midwest ISO filed a proposed modification to the
Midwest ISO Agreement to allow Montana-Dakota to be a separate
pricing zone.  The Midwest ISO commenced security center
operations on December 15, 2001 and tariff administration on
February 1, 2002.

    The Montana legislature passed an electric industry
restructuring bill, effective May 2, 1997.  The bill provided for
full customer choice of electric supplier by July 1, 2002,
stranded cost recovery and other provisions.  Based on the
provisions of such restructuring bill, because Montana-Dakota
operates in more than one state, the company had the option of
deferring its transition to full customer choice until 2006.
Legislation was passed in Montana on March 30, 2001 which delays
the restructuring and transition to full customer choice until a
time that Montana-Dakota can reasonably implement customer choice
in the state of its primary service territory.

    In its 1997 legislative session, the North Dakota
legislature established an Electric Industry Competition
Committee to study over a six-year period the impact of
competition on the generation, transmission and distribution of
electric energy in North Dakota.  To date, the Committee has made
no recommendation regarding restructuring.  In 1997, the WYPSC
selected a consultant to perform a study on the impact of
electric restructuring in Wyoming.  The study found no material
economic benefits.  No further action is pending at this time.
The SDPUC has not initiated any proceedings to date concerning
retail competition or electric industry restructuring.  Federal
legislation addressing this issue continues to be discussed.

    Although Montana-Dakota is unable to predict the outcome of
such regulatory proceedings or legislation, or the extent to
which retail competition may occur, Montana-Dakota is continuing
to take steps to effectively operate in an increasingly
competitive environment.  For additional information regarding
retail competition, see Item 7 -- Management's Discussion and
Analysis of Financial Condition and Results of Operations.

    The NDPSC has authorized its Staff to initiate an
investigation into the earnings levels of Montana-Dakota's North
Dakota electric operations based on Montana-Dakota's 2000 Annual
Report to the NDPSC.  For additional information regarding the
investigation, see Item 7 -- Management's Discussion and Analysis
of Financial Condition and Results of Operations.

    Fuel adjustment clauses contained in North Dakota and South
Dakota jurisdictional electric rate schedules allow
Montana-Dakota to reflect increases or decreases in fuel and
purchased power costs (excluding demand charges) on a timely
basis.  Expedited rate filing procedures in Wyoming allow Montana-
Dakota to timely reflect increases or decreases in fuel and
purchased power costs.  In Montana (23 percent of electric
revenues), such cost changes are includible in general rate
filings.

Environmental Matters --

    Montana-Dakota's electric operations are subject to federal,
state and local laws and regulations providing for air, water and
solid waste pollution control; state facility-siting regulations;
zoning and planning regulations of certain state and local
authorities; federal health and safety regulations and state hazard
communication standards.  Montana-Dakota believes it is in
substantial compliance with those regulations.

    Governmental regulations establishing environmental
protection standards are continuously evolving and, therefore,
the character, scope, cost and availability of the measures which
will permit compliance with these laws or regulations, cannot be
accurately predicted.  Montana-Dakota did not incur any
significant environmental expenditures in 2001 and does not
expect to incur any significant capital expenditures related to
environmental compliance through 2004.

NATURAL GAS DISTRIBUTION

General --

    Montana-Dakota sells natural gas at retail, serving over
213,000 residential, commercial and industrial customers located
in 141 communities and adjacent rural areas as of December 31,
2001, and provides natural gas transportation services to certain
customers on its system.  Great Plains, acquired July 2000, sells
natural gas at retail, serving over 22,000 residential,
commercial and industrial customers located in 19 communities and
adjacent rural areas as of December 31, 2001, and provides
natural gas transportation services to certain customers on its
system.  These services for the two public utility divisions are
provided through distribution systems aggregating over 4,900
miles.  Montana-Dakota and Great Plains have obtained and hold
valid and existing franchises authorizing them to conduct natural
gas distribution operations in all of the municipalities they
serve where such franchises are required.  For additional
information regarding Montana-Dakota's franchises, see Item 7 --
Management's Discussion and Analysis of Financial Condition and
Results of Operations.  As of December 31, 2001, Montana-Dakota's
and Great Plains' net natural gas distribution plant investment
approximated $105.4 million.

    All of Montana-Dakota's natural gas distribution properties,
with certain exceptions, are subject to the lien of the Indenture
of Mortgage dated May 1, 1939, as supplemented, amended and
restated, from the company to The Bank of New York and Douglas J.
MacInnes, successor trustees.

    The natural gas distribution operations of Montana-Dakota are
subject to regulation by the NDPSC, MTPSC, SDPUC and WYPSC
regarding retail rates, service, accounting and, in certain
instances, security issuances.  The natural gas distribution
operations of Great Plains are subject to regulation by the NDPSC
and Minnesota Public Utilities Commission regarding retail rates,
service and accounting.  The percentage of Montana-Dakota's and
Great Plains' 2001 natural gas utility operating revenues by
jurisdiction is as follows:  North Dakota -- 39 percent;
Minnesota -- 11 percent; Montana -- 25 percent; South Dakota -- 19
percent and Wyoming -- 6 percent.

System Supply, System Demand and Competition --

    Montana-Dakota and Great Plains serve retail natural gas
markets, consisting principally of residential and firm
commercial space and water heating users, in portions of the
following states and major communities -- North Dakota, including
Bismarck, Dickinson, Wahpeton, Williston, Minot and Jamestown;
western Minnesota, including Fergus Falls, Marshall and
Crookston; eastern Montana, including Billings, Glendive and
Miles City; western and north-central South Dakota, including
Rapid City, Pierre and Mobridge; and northern Wyoming, including
Sheridan.  These markets are highly seasonal and sales volumes
depend on the weather.

    The following table reflects this segment's natural gas
sales, natural gas transportation volumes and degree days as a
percentage of normal during the last five years:

                               Years Ended December 31,
                          2001*   2000**   1999     1998     1997
                                 Mdk (thousands of decatherms)

Sales:
  Residential           20,087  20,554   18,059   18,614   20,126
  Commercial            14,661  14,590   12,030   12,458   13,799
  Industrial             1,731   1,451      842      952      395
    Total               36,479  36,595   30,931   32,024   34,320
Transportation:
  Commercial             1,847   2,067    1,975    1,995    1,612
  Industrial            12,491  12,247    9,576    8,329    8,455
    Total               14,338  14,314   11,551   10,324   10,067
Total Throughput        50,817  50,909   42,482   42,348   44,387

Degree days
  (% of normal)          94.5%  100.4%    88.8%    93.7%    99.3%

 * Includes Great Plains
** Sales and transportation volumes for Great Plains are for the
   period July through December 2000.  Degree days exclude Great
   Plains.

    Competition in varying degrees exists between natural gas and
other fuels and forms of energy.  Montana-Dakota and Great Plains
have established various natural gas transportation service rates
for their distribution businesses to retain interruptible
commercial and industrial load.  Certain of these services
include transportation under flexible rate schedules whereby
Montana-Dakota's and Great Plains' interruptible customers can
avail themselves of the advantages of open access transportation
on regional transmission pipelines, including the system of
Williston Basin Interstate Pipeline Company (Williston Basin), an
indirect wholly owned subsidiary of WBI Holdings.  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, which did not have a material effect on
results of operations.

    Montana-Dakota and Great Plains acquire their system
requirements directly from producers, processors and marketers.
Such natural gas is supplied by a portfolio of contracts
specifying market-based pricing, and is transported under
transportation agreements by Williston Basin, Northern Gas
Company, South Dakota Intrastate Pipeline Company, Northern
Border Pipeline Company, Viking Gas Transmission Company and
Northern Natural Gas Company to provide firm service to their
customers.  Montana-Dakota has also contracted with Williston
Basin to provide firm storage services which enable Montana-
Dakota to meet winter peak requirements as well as allow it to
better manage its natural gas costs by purchasing natural gas at
more uniform daily volumes throughout the year.  Demand for
natural gas, which is a widely traded commodity, is sensitive to
seasonal heating and industrial load requirements as well as
changes in market price.  Montana-Dakota and Great Plains believe
that, based on regional supplies of natural gas and the pipeline
transmission network currently available through its suppliers
and pipeline service providers, supplies are adequate to meet its
system natural gas requirements for the next five years.

Regulatory Matters --

    Montana-Dakota's and Great Plains' retail natural gas rate
schedules contain clauses permitting monthly adjustments in rates
based upon changes in natural gas commodity, transportation and
storage costs.  Current regulatory practices allow Montana-Dakota
and Great Plains to recover increases or refund decreases in such
costs within a period ranging from 24 months to 28 months from
the time such changes occur.

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.

UTILITY SERVICES

    Utility Services is a diversified infrastructure company
specializing in electric, gas and telecommunication utility
construction, as well as interior industrial electrical,
exterior lighting and traffic signalization.  Utility Services
has engineering, design and build capability and provides
related specialty equipment manufacturing, sales and rental
services.  These services are provided to electric, gas and
telecommunication companies along with municipal, commercial
and industrial entities throughout most of the United States.

    During 2001, the company acquired utility services businesses
based in Missouri and Oregon.  None of these acquisitions was
individually material to the company.

    Utility Services operates in a highly competitive business
environment.  Most of Utility Services' work is obtained on the
basis of competitive bids or by negotiation of either cost plus
or fixed price contracts.  The workforce and equipment are highly
mobile, providing greater flexibility in the size and location of
Utility Services' market area.  Competition is based primarily on
price and reputation for quality, safety and reliability.  The
size and area location of the services provided will be a factor
in the number of competitors that Utility Services will encounter
on any particular project.  Utility Services believes that the
diversification of the services it provides will enable it to
effectively operate in this competitive environment.

    Utilities and independent contractors represent the largest
customer base.  Accordingly, utility and sub-contract work
accounts for a significant portion of the work performed by the
utility services segment and the amount of construction contracts
is dependent to a certain extent on the level and timing of
maintenance and construction programs undertaken by customers.
Utility Services relies on repeat customers and strives to
maintain successful long-term relationships with these customers.

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

    Utility services operates a fleet of owned and leased trucks
and trailers, support vehicles and specialty construction
equipment, such as backhoes, excavators, trenchers, generators,
boring machines and cranes.  In addition, as of December 31,
2001, Utility Services owned or leased offices in 10 states.
This space is used for offices, equipment yards, warehousing,
storage and vehicle shops.  At December 31, 2001, Utility
Service's net plant investment was approximately $45.2 million.

    The utility services segment backlog is comprised of the
uncompleted portion of services to be performed under job-
specific contracts and the estimated value of future services
that it expects to provide under other master agreements.  The
backlog at January 31, 2002 was approximately $142 million.  The
company expects to complete a significant amount of the backlog
during the year ending December 31, 2002.  Due to the nature of
its contractual arrangements, in many instances the company's
customers are not committed to the specific volumes of services
to be purchased under a contract, but rather the company is
committed to perform these services if and to the extent
requested by the customer.  The customer is, however, obligated
to obtain these services from the company if they are not
performed by the customer's employees.  Therefore, there can be
no assurance as to the customer's requirements during a
particular period or that such estimates at any point in time are
accurate.

PIPELINE AND ENERGY SERVICES

General --

    Williston Basin, the principal regulated business of WBI
Holdings, owns and operates over 3,400 miles of transmission,
gathering and storage lines and owns or leases and operates 24
compressor stations located in the states of Montana, North
Dakota, South Dakota and Wyoming.  Through three underground
storage fields located in Montana and Wyoming, storage
services are provided to local distribution companies,
producers, 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.

    At December 31, 2001, Williston Basin's net plant investment
was approximately $158.2 million.

    WBI Holdings owns and operates gathering facilities in
Colorado, Kansas, Montana and Wyoming.  These facilities include
approximately 1,500 miles of field gathering lines and 84 owned
compression facilities some of which interconnect with Williston
Basin's system.  A one-sixth interest in the assets of various
offshore gathering pipelines and associated onshore pipeline and
related processing facilities are also owned by WBI Holdings.

    WBI Holdings, through its energy services businesses,
provides natural gas purchase and sales services to large end
users, local distribution companies and other marketers.  Energy
services transacts a significant portion of its business in the
Northern Plains and Rocky Mountain regions of the United States.
In 2001, the company sold the majority of its Kentucky-based
energy marketing operations that served customers in the southern
and central portions of the United States.  Energy services
provides installation sales and/or leasing of alternate energy
delivery systems, primarily propane air plants, as well as
providing energy efficiency product sales and installation
services to large end users.

    Energy services also owns a cable and pipeline surveying and
locating company.  This company provides products and services
which are an integral part of the ongoing reliability of the
submerged cable and pipeline infrastructure.  In 2001, a
manufacturer and reseller of on-land, hand-held equipment used
for locating and identifying underground metal objects, utility
systems and water distribution system leaks was acquired.

    Under the Natural Gas Act, as amended, Williston Basin and
certain other operations of WBI Holdings are subject to the
jurisdiction of the FERC regarding certificate, rate, service and
accounting matters.

System Demand and Competition --

    Williston Basin competes with several pipelines for its
customers' transportation business and at times may discount
rates in an effort to retain market share. However, the strategic
location of Williston Basin's system near five natural gas
producing basins and the availability of underground storage and
gathering services provided by Williston Basin and affiliates
along with interconnections with other pipelines serve to enhance
Williston Basin's competitive position.

    Although a significant portion of Williston Basin's firm
customers, which include Montana-Dakota, have relatively secure
residential and commercial end-users, virtually all have some
price-sensitive end-users that could switch to alternate fuels.

    Williston Basin transports substantially all of Montana-
Dakota's natural gas utilizing firm transportation agreements,
which at December 31, 2001, represented 84 percent of Williston
Basin's currently subscribed firm transportation capacity.  In
October 2001, Montana-Dakota executed a firm transportation
agreement with Williston Basin for a term of five years expiring
in June 2007.  In addition, in July 1995, Montana-Dakota entered
into a 20-year contract with Williston Basin to provide firm
storage services to facilitate meeting Montana-Dakota's winter
peak requirements.

    On November 30, 2001, Williston Basin filed for regulatory
approval to build a 247-mile, 16-inch natural gas pipeline that
would span sections of Wyoming, Montana, and North Dakota.  The
pipeline would transport natural gas from developing coalbed and
conventional natural gas production in central Wyoming and south
central Montana to interconnecting pipelines.  Depending upon the
timing of the receipt of the necessary regulatory approval,
construction completion could occur as early as late 2002 to mid-
2003.

System Supply --

    Williston Basin's underground storage facilities have a
certificated storage capacity of approximately 353 billion cubic
feet (Bcf), including 193 Bcf of working gas capacity, 85 Bcf of
cushion gas and 75 Bcf of native gas.  The native gas includes 29
Bcf of recoverable gas.  Williston Basin's storage facilities
enable its customers to purchase natural gas at more uniform
daily volumes throughout the year and, thus, facilitate meeting
winter peak requirements.

    Natural gas supplies from traditional regional sources have
declined during the past several years and such declines are
anticipated to continue.  As a result, Williston Basin
anticipates that a potentially significant amount of the future
supply needed to meet its customers' demands will come from non-
traditional, off-system sources.  The company's coalbed natural
gas assets in the Powder River Basin are expected to meet some of
these supply needs.  Williston Basin expects to facilitate the
movement of these supplies by making available its transportation
and storage services.  Williston Basin will continue to look for
opportunities to increase transportation and storage services
through system expansion or other pipeline interconnections or
enhancements which could provide substantial future benefits.

Regulatory Matters and Revenues Subject to Refund --

    In December 1999, Williston Basin filed a general natural
gas rate change application with the FERC.  Williston Basin began
collecting such rates effective June 1, 2000, subject to refund.
On May 9, 2001, the Administrative Law Judge issued an Initial
Decision on Williston Basin's natural gas rate change
application, which matter is currently pending before and subject
to revision by the FERC.

    Reserves have been provided for a portion of the revenues
that have been collected subject to refund with respect to the
pending regulatory proceeding.  Williston Basin, in the fourth
quarter of 2000, determined that reserves it had previously
established for certain regulatory proceedings, prior to the
proceeding filed in 1999, exceeded its expected refund obligation
and, accordingly, reversed reserves and recognized in income $6.7
million after-tax.  Williston Basin, in the second quarter of
1999, determined that reserves it had previously established in
relation to a 1992 general natural gas rate change application
and the 1995 general rate increase application exceeded its
expected refund obligation and, accordingly, reversed reserves
and recognized in income $4.4 million after-tax.  Williston Basin
believes that its remaining reserves are adequate based on its
assessment of the ultimate outcome of the application filed in
December 1999.

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.

NATURAL GAS AND OIL PRODUCTION

General --

    Fidelity Exploration & Production Company (Fidelity), a
direct wholly owned subsidiary of WBI Holdings, is involved in
the acquisition, exploration, development and production of
natural gas and oil resources.  Fidelity's activities include the
acquisition of producing properties with potential development
opportunities, exploratory drilling and the operation and
development of natural gas production properties.  Fidelity
shares revenues and expenses from the development of specified
properties located primarily in the Rocky Mountain region of the
United States and in the Gulf of Mexico in proportion to its
interests.

    Fidelity owns in fee or holds natural gas leases for the
properties it operates in Colorado, Montana, North Dakota and
Wyoming.  These rights are in the Bonny Field located in eastern
Colorado, the Cedar Creek Anticline in southeastern Montana and
southwestern North Dakota, the Bowdoin area located in north-
central Montana and in the Powder River Basin of Wyoming and
Montana.

    Fidelity continues to seek additional reserve and production
opportunities through the direct acquisition of producing
properties and through exploratory drilling opportunities, as
well as development of its existing properties.  Future growth is
dependent upon its continuing success in these endeavors.

Operating Information --

    Information on natural gas and oil production, average
realized prices and production costs per net equivalent Mcf
related to natural gas and oil interests for 2001, 2000 and 1999,
are as follows:

                                          2001     2000     1999
Natural Gas:
  Production (MMcf)                     40,591   29,222   24,652
  Average realized price                 $3.78    $2.90    $1.94
Oil:
  Production (000's of barrels)          2,042    1,882    1,758
  Average realized price                $24.59   $23.06   $15.34
Production costs, including taxes,
  per net equivalent Mcf                 $0.84    $0.77    $0.62

Well and Acreage Information --

  Gross and net productive well counts and gross and net
developed and undeveloped acreage related to interests at
December 31, 2001, are as follows:

                                                   Gross     Net
Productive Wells:
  Natural Gas                                      3,455    1,768
  Oil                                              3,095      164
    Total                                          6,550    1,932
Developed Acreage (000's)                          1,195      600
Undeveloped Acreage (000's)                          856      332

Exploratory and Development Wells --

  The following table shows the results of natural gas and oil
wells drilled and tested during 2001, 2000 and 1999:

           Net Exploratory              Net Development
        Productive  Dry Holes  Total    Productive  Dry Holes  Total   Total
2001            19          1     20           532         60    592     612
2000             9          3     12           362          3    365     377
1999             1          2      3            70          2     72      75

    At December 31, 2001, there were seven gross wells in the
process of drilling, all of which were development wells.

Environmental Matters --

    WBI Holdings' natural gas and oil production operations are
generally subject to federal, state and local environmental,
facility-siting, zoning and planning laws and regulations.  WBI
Holdings believes it is in substantial compliance with those
regulations.

Reserve Information --

    Fidelity's recoverable proved developed and undeveloped
natural gas and oil reserves approximated 324.1 Bcf and 17.5
million barrels, respectively, at December 31, 2001.

    For additional information related to natural gas and oil
interests, see Notes 1 and 17 of Notes to Consolidated Financial
Statements.


CONSTRUCTION MATERIALS AND MINING

Construction Materials:

General --

    Knife River operates construction materials and mining
businesses in Alaska, California, Hawaii, Minnesota, Montana,
Oregon and Wyoming.  These operations mine, process and sell
construction aggregates (crushed stone, sand and gravel) and
supply ready-mixed concrete for use in most types of
construction, including homes, schools, shopping centers, office
buildings and industrial parks as well as roads, freeways and
bridges.

    In addition, certain operations produce and sell asphalt for
various commercial and roadway applications.  Although not common
to all locations, other products include the sale of cement,
various finished concrete products and other building materials
and related construction services.

    During 2001, the company acquired several construction
materials and mining businesses with operations in Hawaii,
Minnesota and Oregon.  None of these acquisitions was
individually material to the company.

    Knife River's construction materials business has continued
to grow since its first acquisition in 1992.  Knife River
continues to investigate the acquisition of other construction
materials properties, particularly those relating to sand and
gravel aggregates and related products such as ready-mixed
concrete, asphalt and various finished aggregate products.

    Knife River's construction materials business is expected to
continue to benefit from the Transportation Equity Act for the
21st Century (TEA-21).  TEA-21 represents an average increase in
federal highway construction funding of approximately 48 percent
for the six fiscal years ending 2003.

    The construction materials business had approximately $162
million in backlog in mid-February 2002, compared to
approximately $126 million in mid-February 2001.  The company
anticipates that a significant amount of the current backlog will
be completed during the year ending December 31, 2002.

Competition --

    Knife River's construction materials products are marketed
under highly competitive conditions.  Since there are generally
no measurable product differences in the market areas in which
Knife River conducts its construction materials businesses, price
is the principal competitive force to which these products are
subject, with service, delivery time and proximity to the
customer also being significant factors.  The number and size of
competitors varies in each of Knife River's principal market
areas and product lines.

    The demand for construction materials products is
significantly influenced by the cyclical nature of the
construction industry in general.  In addition, construction
materials activity in certain locations may be seasonal in nature
due to the effects of weather.  The key economic factors
affecting product demand are changes in the level of local, state
and federal governmental spending, general economic conditions
within the market area which influence both the commercial and
private sectors, and prevailing interest rates.

    Knife River is not dependent on any single customer or group
of customers for sales of its construction materials products,
the loss of which would have a materially adverse affect on its
construction materials businesses.

Coal:

General --

    In 2001, the company sold its coal operations to
Westmoreland for $28.2 million in cash, including final
settlement cost adjustments.  For more information on the
sale see Information contained in Item 7 -- Management's
Discussion and Analysis of Financial Condition and Results
of Operations.

    During the last five years, Knife River mined and sold
the following amounts of lignite coal:

                                 Years Ended December 31,
                          2001*   2000    1999    1998    1997
                                     (In thousands)

Tons  sold               1,171   3,111   3,236   3,113   2,375
Revenues               $12,303 $33,721 $34,841 $35,949 $27,906

* Coal operations were sold effective April 30, 2001.


Consolidated Construction Materials and Mining:

Environmental Matters --

    Knife River's construction materials and mining operations
are subject to regulation customary for surface mining
operations, including federal, state and local environmental and
reclamation regulations.  Except as what may be ultimately
determined with regard to the issue described below, Knife River
believes it is in substantial compliance with those regulations.

    In December 2000, Morse Bros., Inc. (MBI), an indirect wholly
owned subsidiary of the company, was named by the United States
Environmental Protection Agency (EPA) as a Potentially
Responsible Party in connection with the cleanup of a commercial
property site, now owned by MBI, and part of the Portland,
Oregon, Harbor Superfund Site.  Sixty-eight other parties were
also named in this administrative action.  The EPA wants
responsible parties to share in the cleanup of sediment
contamination in the Williamette River.  Based upon a review of
the Portland Harbor sediment contamination evaluation by the
Oregon State Department of Environmental Quality and other
information available, MBI does not believe it is a Responsible
Party.  In addition, MBI intends to seek indemnity for any and
all liabilities incurred in relation to the above matters from
Georgia-Pacific West, Inc., the seller of the commercial property
site to MBI, pursuant to the terms of their sale agreement.

Reserve Information --

    As of December 31, 2001, the combined construction materials
operations had under ownership or lease approximately 1.1 billion
tons of recoverable aggregate reserves.

    As of December 31, 2001, Knife River had under ownership or
lease, reserves of approximately 56.0 million tons of recoverable
lignite coal.

ITEM 3.  LEGAL PROCEEDINGS

    In March 1997, 11 natural gas producers filed suit in North
Dakota Southwest Judicial District Court (North Dakota District
Court) against Williston Basin and the company.  The natural gas
producers had processing agreements with Koch Hydrocarbon Company
(Koch).  Williston Basin and the company had natural gas purchase
contracts with Koch.  The natural gas producers alleged they were
entitled to damages for the breach of Williston Basin's and the
company's contracts with Koch although no specific damages were
stated.  A similar suit was filed by Apache Corporation (Apache)
and Snyder Oil Corporation (Snyder) in North Dakota Northwest
Judicial District Court in December 1993.  The North Dakota
Supreme Court in December 1999 affirmed the North Dakota
Northwest Judicial District Court decision dismissing Apache's
and Snyder's claims against Williston Basin and the company.
Based in part upon the decision of the North Dakota Supreme Court
affirming the dismissal of the claims brought by Apache and
Snyder, Williston Basin and the company filed motions for summary
judgment to dismiss the claims of the 11 natural gas producers.
The motions for summary judgment were granted by the North Dakota
District Court in July 2000.  On March 5, 2001, the North Dakota
District Court entered a final judgment on the July 2000 order
granting the motions for summary judgment.  On May 4, 2001, the
11 natural gas producers appealed the North Dakota District
Court's decision by filing a Notice of Appeal with the North
Dakota Supreme Court.  Oral argument was held before the North
Dakota Supreme Court on December 12, 2001.  Williston Basin and
the company are awaiting a decision from the North Dakota Supreme
Court.

    In July 1996, Jack J. Grynberg (Grynberg) filed suit in
United States District Court for the District of Columbia (U.S.
District Court) against Williston Basin and over 70 other natural
gas pipeline companies.  Grynberg, acting on behalf of the United
States under the Federal False Claims Act, alleged improper
measurement of the heating content or volume of natural gas
purchased by the defendants resulting in the underpayment of
royalties to the United States.  In March 1997, the U.S. District
Court dismissed the suit without prejudice and the dismissal was
affirmed by the United States Court of Appeals for the D.C.
Circuit in October 1998.  In June 1997, Grynberg filed a similar
Federal False Claims Act suit against Williston Basin and Montana-
Dakota and filed over 70 other separate similar suits against
natural gas transmission companies and producers, gatherers, and
processors of natural gas.  In April 1999, the United States
Department of Justice decided not to intervene in these cases.
In response to a motion filed by Grynberg, the Judicial Panel on
Multidistrict Litigation consolidated all of these cases in the
Federal District Court of Wyoming (Federal District Court).  Oral
argument on motions to dismiss was held before the Federal
District Court in March 2000.  On May 18, 2001, the Federal
District Court denied Williston Basin's and Montana-Dakota's
motion to dismiss.  The matter is currently pending.

    The Quinque Operating Company (Quinque), on behalf of itself
and subclasses of gas producers, royalty owners and state taxing
authorities, instituted a legal proceeding in State District
Court for Stevens County, Kansas,(State District Court) against
over 200 natural gas transmission companies and producers,
gatherers, and processors of natural gas, including Williston
Basin and Montana-Dakota.  The complaint, which was served on
Williston Basin and Montana-Dakota in September 1999, contains
allegations of improper measurement of the heating content and
volume of all natural gas measured by the defendants other than
natural gas produced from federal lands.  In response to a motion
filed by the defendants in this suit, the Judicial Panel on
Multidistrict Litigation transferred the suit to the Federal
District Court for inclusion in the pretrial proceedings of the
Grynberg suit.  Upon motion of plaintiffs, the case has been
remanded to State District Court.  On September 12, 2001, the
defendants in this suit filed a motion to dismiss with the State
District Court.  The matter is currently pending.

    Williston Basin and Montana-Dakota believe the claims of
Grynberg and Quinque are without merit and intend to vigorously
contest these suits.

    In December 2000, MBI, an indirect wholly owned subsidiary of
the company, was named by the United States Environmental
Protection Agency (EPA) as a Potentially Responsible Party in
connection with the cleanup of a commercial property site, now
owned by MBI, and part of the Portland, Oregon, Harbor Superfund
Site.  For additional information regarding this issue, see Items
1 and 2 -- Business and Properties -- Construction Materials and
Mining.

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 2001.

                             PART II

ITEM 5.   MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
          STOCKHOLDER MATTERS

    The company's common stock is listed on the New York Stock
Exchange and the Pacific Stock Exchange under the symbol "MDU."
The price range of the company's common stock as reported by The
Wall Street Journal composite tape during 2001 and 2000 and
dividends declared thereon were as follows:

                                                       Common
                             Common       Common        Stock
                            Stock Price  Stock Price   Dividends
                              (High)      (Low)        Per Share

2001
First Quarter                $ 35.76      $ 27.38       $   .22
Second Quarter                 40.37        31.38           .22
Third Quarter                  32.90        22.38           .23
Fourth Quarter                 28.30        23.00           .23
                                                        $   .90

2000
First Quarter                $ 21.44      $ 17.63       $   .21
Second Quarter                 23.25        20.38           .21
Third Quarter                  30.06        21.56           .22
Fourth Quarter                 33.00        27.44           .22
                                                        $   .86

    As of December 31, 2001, the company's common stock was held
by approximately 14,000 stockholders of record.

    Between October 1, 2001 and December 31, 2001, the company
issued 58,816 shares of Common Stock, $1.00 par value as partial
consideration with respect to an acquisition in a prior period.
The Common Stock issued by the company in this transaction was
issued in private sales exempt from registration pursuant to
Section 4(2) of the Securities Act of 1933.  The holder is an
accredited investor and acknowledged that it would hold the
company's Common Stock as an investment and not with a view to
distribution.

ITEM 6.  SELECTED FINANCIAL DATA

    Reference is made to Selected Financial Data on pages 62 and
63 of the company's Annual Report which is incorporated herein by
reference.

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

    For purposes of segment financial reporting and discussion
of results of operations, electric and natural gas distribution
include the electric and natural gas distribution operations of
Montana-Dakota and the natural gas distribution operations of
Great Plains Natural Gas Co.  Utility services includes all the
operations of Utility Services, Inc.  Pipeline and energy
services includes WBI Holdings' natural gas transportation,
underground storage, gathering services, energy marketing and
management services; Centennial Capital, which invests in
domestic growth opportunities; and MDU International, which
invests in international growth opportunities.  Natural gas and
oil production includes the natural gas and oil acquisition,
exploration and production operations of WBI Holdings, while
construction materials and mining includes the results of Knife
River's operations.

    Reference should be made to Items 1 and 2 -- Business and
Properties, Item 3 -- Legal Proceedings and Notes to Consolidated
Financial Statements for information pertinent to various
commitments and contingencies.

Overview

    The following table (dollars in millions, where applicable)
summarizes the contribution to consolidated earnings by each of
the company's business segments.

                                        Years ended December 31,
                                       2001      2000        1999
Electric                            $  18.7   $  17.7     $  16.0
Natural gas distribution                 .7       4.8         3.2
Utility services                       12.9       8.6         6.5
Pipeline and energy services           16.4      10.5        21.0
Natural gas and oil production         63.2      38.6        16.2
Construction materials and mining      43.2      30.1        20.4
Earnings on common stock            $ 155.1   $ 110.3     $  83.3

Earnings per common share - basic   $  2.31   $  1.80     $  1.53

Earnings per common share - diluted $  2.29   $  1.80     $  1.52

Return on average common equity       15.3%     14.3%       13.9%

2001 compared to 2000

    Consolidated earnings for 2001 increased $44.8 million from
the comparable period a year ago due to higher earnings from the
natural gas and oil production, construction materials and
mining, pipeline and energy services, utility services and
electric businesses.  Lower earnings at the natural gas
distribution business partially offset the earnings increase.


2000 compared to 1999

    Consolidated earnings for 2000 increased $27.0 million from
the comparable period a year ago due to higher earnings from the
natural gas and oil production, construction materials and
mining, utility services, electric and natural gas distribution
businesses.  Lower earnings at the pipeline and energy services
business partially offset the earnings increase.

                 ________________________________

Financial and Operating Data

     The following tables (dollars in millions, where applicable)
are key financial and operating statistics for each of the
company's business segments.

Electric
                                          Years ended December 31,
                                         2001       2000       1999
Operating revenues:
  Retail sales                      $   137.3  $   134.5   $  130.9
  Sales for resale and other             31.5       27.1       24.0
                                        168.8      161.6      154.9
Operating expenses:
  Fuel and purchased power               57.4       54.1       51.8
  Operation and maintenance              45.6       42.5       41.6
  Depreciation, depletion and
    amortization                         19.5       19.1       18.4
  Taxes, other than income                7.6        7.1        7.4
                                        130.1      122.8      119.2

Operating income                    $    38.7  $    38.8   $   35.7

Retail sales (million kWh)            2,177.9    2,161.3    2,075.5
Sales for resale (million kWh)          898.2      930.3      943.5
Average cost of fuel and
  purchased power per kWh           $    .018  $    .016   $   .016


Natural Gas Distribution
                                          Years ended December 31,
                                         2001       2000       1999
Operating revenues:
  Sales                             $   251.3  $   229.2   $  154.1
  Transportation and other                4.1        3.9        3.6
                                        255.4      233.1      157.7
Operating expenses:
 Purchased natural gas sold             200.7      178.6      110.2
  Operation and maintenance              36.6       32.0       29.2
  Depreciation, depletion and
    amortization                          9.4        8.4        7.4
  Taxes, other than income                5.1        4.6        4.2
                                        251.8      223.6      151.0

Operating income                    $     3.6  $     9.5   $    6.7

Volumes (MMdk):
  Sales                                  36.5       36.6       30.9
  Transportation                         14.3       14.3       11.6
Total throughput                         50.8       50.9       42.5

Degree days (% of normal)               94.5%     100.4%      88.8%
Average cost of natural gas,
  including transportation
  thereon, per dk                   $    5.50  $    4.88   $   3.56


Utility Services

                                          Years ended December 31,
                                         2001       2000       1999

Operating revenues                  $   364.8  $   169.4   $   99.9

Operating expenses:
 Operation and maintenance              321.0      142.6       82.8
 Depreciation, depletion and
    amortization                          8.4        4.9        2.6
 Taxes, other than income                10.2        5.3        3.0
                                        339.6      152.8       88.4

Operating income                    $    25.2  $    16.6   $   11.5


Pipeline and Energy Services

                                          Years ended December 31,
                                         2001       2000       1999
Operating revenues:
  Pipeline                          $    87.1  $    77.4   $   69.6
  Energy services                       444.0      559.4      313.9
                                        531.1      636.8      383.5
Operating expenses:
  Purchased natural gas sold            433.5      548.3      301.5
  Operation and maintenance              47.1       39.1       28.2
  Depreciation, depletion and
    amortization                         14.3       15.3        8.2
  Taxes, other than income                5.8        5.3        5.0
                                        500.7      608.0      342.9

Operating income                    $    30.4  $    28.8   $   40.6

Transportation volumes (MMdk):
  Montana-Dakota                         34.1       30.6       31.5
  Other                                  63.1       56.2       46.6
                                         97.2       86.8       78.1

Gathering volumes (MMdk)                 61.1       41.7       19.8


Natural Gas and Oil Production

                                          Years ended December 31,
                                         2001       2000       1999
Operating revenues:
  Natural gas                       $   153.3  $    84.7   $   47.9
  Oil                                    50.2       43.4       26.9
  Other                                   6.3       10.2        3.6
                                        209.8      138.3       78.4
Operating expenses:
  Purchased natural gas sold              2.8        3.4        1.5
  Operation and maintenance              50.4       31.3       24.8
  Depreciation, depletion and
    amortization                         41.7       27.0       19.2
  Taxes, other than income               11.0       10.1        6.0
                                        105.9       71.8       51.5

Operating income                    $   103.9  $    66.5   $   26.9

Production:
  Natural gas (MMcf)                   40,591     29,222     24,652
  Oil (000's of barrels)                2,042      1,882      1,758

Average realized prices:
  Natural gas (per Mcf)             $    3.78  $    2.90   $   1.94
  Oil (per barrel)                  $   24.59  $   23.06   $  15.34


Construction Materials and Mining

                                          Years ended December 31,
                                         2001       2000       1999
Operating revenues:
  Construction materials            $   794.6  $   597.7   $  435.1
  Coal                                   12.3*      33.7       34.8
                                        806.9      631.4      469.9
Operating expenses:
  Operation and maintenance             673.1      526.0      397.9
  Depreciation, depletion and
    amortization                         46.6       36.2       26.0
  Taxes, other than income               15.7       12.4        7.6
                                        735.4      574.6      431.5

Operating income                    $    71.5  $    56.8   $   38.4

Sales (000's):
  Aggregates (tons)                    27,565     18,315     13,981
  Asphalt (tons)                        6,228      3,310      2,993
  Ready-mixed concrete
    (cubic yards)                       2,542      1,696      1,186
  Coal (tons)                           1,171*     3,111      3,236
______________________________
* Coal operations were sold effective April 30, 2001.

    Amounts presented in the preceding tables for operating
revenues, purchased natural gas sold and operation and
maintenance expense will not agree with the Consolidated
Statements of Income due to the elimination of intercompany
transactions between the pipeline and energy services segment
and the natural gas distribution and natural gas and oil
production segments.  The amounts relating to the elimination
of intercompany transactions for operating revenues,
purchased natural gas sold and operation and maintenance
expense are as follows:  $113.2 million, $107.7 million and
$5.5 million for 2001; $96.9 million, $96.0 million and $.9
million for 2000; and $64.5 million, $64.0 million and $.5
million for 1999, respectively.

2001 compared to 2000

Electric

    Electric earnings increased due to higher average
realized sales for resale prices, decreased interest expense
due to lower average borrowings, and insurance recovery
proceeds related to a 2000 outage at an electric generating
station.  Higher operation and maintenance expense, primarily
increased payroll expense and higher subcontractor costs, and
increased fuel and purchased power costs, largely higher
demand charge costs related to an extended maintenance outage
at an electric power supplier's generating station, partially
offset the earnings increase.  Also partially offsetting the
earnings increase were lower sales for resale volumes, and
increased depreciation, depletion and amortization expense
resulting from higher property, plant and equipment balances.

Natural Gas Distribution

    Earnings at the natural gas distribution business
decreased as a result of lower sales volumes, largely the
result of weather in the fourth quarter which was 22 percent
warmer than a year ago, and higher operation and maintenance
expenses, primarily increased payroll costs and higher bad
debt expense.  Lower average realized rates, return on
natural gas storage, demand and prepaid commodity balances,
and decreased service and repair margins also added to the
earnings decline.  Slightly offsetting the decline were
decreased interest expense due to lower average borrowings,
and earnings from a natural gas utility business acquired in
July 2000.  The pass-through of higher natural gas prices
resulted in the increase in sales revenue and purchased
natural gas sold.

Utility Services

    Utility services earnings increased as a result of earnings
from businesses acquired since the comparable period last year,
slightly higher operating margins from existing operations and
decreased interest expense due to lower average interest rates.
The earnings improvement was partially offset by higher selling,
general and administrative costs.

Pipeline and Energy Services

    Earnings at the pipeline and energy services business
increased due to higher transportation and gathering volumes at
higher average rates at the pipeline.  The absence in 2001 of an
asset impairment recognized in 2000 in the amount of $3.9 million
after-tax at one of the company's energy services companies and
the net effect of the sale in 2001 of certain smaller
nonstrategic properties at the pipeline also added to the
earnings increase.  In addition, higher natural gas sales margins
at energy services added to the earnings increase.  Partially
offsetting the earnings increase were the absence in 2001 of a
2000 $6.7 million after-tax reserve revenue adjustment and
resulting increase to income relating to certain regulatory
proceedings, prior to the proceeding filed in 1999, and higher
operation and maintenance expense.  The write-off of an
investment in a software development company of $699,000 (after-
tax) and expenses incurred for corporate development costs in
connection with the pursuit of electric generation opportunities
in Brazil also partially offset the earnings increase.  The
higher operation and maintenance expense was due primarily to
increased compressor-related expenses in connection with the
expansion of the gathering systems.  The decrease in energy
services revenue and the related decrease in purchased natural
gas sold resulted from decreased energy marketing sales volumes
at certain energy services operations that were sold in 2001.

Natural Gas and Oil Production

    Natural gas and oil production earnings increased largely due
to higher natural gas and oil production of 39 percent and 9
percent since last year, respectively, combined with increased
realized natural gas and oil prices which were 30 percent and 7
percent higher than last year, respectively.  The higher
production was largely the result of a natural gas property
acquisition in April 2000 and the ongoing development of that
property as well as existing properties.  Also adding to the
earnings increase was lower interest expense, a result of lower
debt balances combined with lower average rates.  Partially
offsetting the earnings improvement were increased operation and
maintenance expense, mainly higher lease operating expenses and
higher general and administrative costs.  Increased depreciation,
depletion and amortization expense due to higher production
volumes and higher rates, and lower sales volumes of inventoried
natural gas also partially offset the earnings increase.  Hedging
activities for natural gas and oil production for 2001 resulted
in realized prices that were 101 percent and 104 percent,
respectively, of what otherwise would have been received.

Construction Materials and Mining

    Earnings for the construction materials and mining business
increased largely due to earnings from businesses acquired since
the comparable period last year and increases at existing
asphalt, aggregate, cement and ready-mixed concrete construction
materials operations.  Also adding to the earnings increase was a
one-time gain from the sale of the coal operations of $10.3
million ($6.2 million after-tax, including final settlement cost
adjustments), included in other income - net, as discussed in
Note 10 of Notes to Consolidated Financial Statements, partially
offset by lower coal sales volumes due primarily to four months
of operations in 2001 compared to 12 months in 2000.  Also
partially offsetting the earnings increase were lower
construction margins, largely resulting from increased
competition and less available work, and the absence in 2001 of a
2000 gain of $1.2 million after-tax on the sale of a nonstrategic
property.  Increased interest expense due to higher acquisition-
related borrowings, higher depreciation, depletion and
amortization expense due to increased plant balances, and higher
selling, general and administrative costs also partially offset
the earnings improvement.

2000 compared to 1999

Electric

    Electric earnings increased due to higher demand-related
retail sales to all major customer classes, higher average
realized rates and lower employee benefit-related expenses.
Increased fuel and purchased power costs, largely higher
purchased power costs, increased coal costs, and higher
natural gas generation-related costs, partially offset the
earnings increase.  Higher maintenance expense at certain of
the company's electric generating stations, and increased
depreciation, depletion and amortization expense, resulting
from higher property, plant and equipment balances, also
partially offset the earnings increase.

Natural Gas Distribution

    Earnings improved at the natural gas distribution
business largely due to higher weather-related retail sales
volumes resulting from weather in the fourth quarter which
was 46 percent colder than the same period in 1999.
Increased service and repair margins, earnings from Great
Plains, which was acquired in July 2000, and higher
transportation volumes also added to the earnings increase.
Increased depreciation, depletion and amortization expense,
due to higher property, plant and equipment balances, and
lower average realized transportation rates, partially offset
the earnings increase.

Utility Services

    Utility services earnings increased as a result of earnings
from businesses acquired since the comparable period in 1999,
higher work load in the Rocky Mountain region, primarily related
to fiber optic installation projects, and increases from
engineering services.  This increase was somewhat offset by
decreased construction activity for utilities on the West Coast,
largely the result of utility merger activity and the California
energy crisis.

Pipeline and Energy Services

    Pipeline and energy services earnings decreased primarily
due to the absence in 2000 of a 1999 $4.4 million after-tax
reserve revenue adjustment and resulting increase to income
associated with FERC orders received in the 1992 and 1995
general rate proceedings, the recognition in 1999 of a $3.9
million after-tax reserve adjustment and resulting increase to
income relating to the resolution of certain production tax
and other state tax matters, and the recognition in income in
1999 of $1.7 million after-tax resulting from a favorable
order received from the United States Court of Appeals for the
D.C. Circuit Court relating to the 1992 general rate
proceeding.  An asset impairment charge of $3.9 million after-
tax in 2000 at one of the company's energy services companies
also lowered earnings.  In addition, higher bad debt expense
and lower natural gas margins from energy services, and higher
operation and maintenance expenses at the pipeline, largely
higher compressor-related expenses and payroll costs,
contributed to the decline in earnings.  Partially offsetting
the decline in earnings was the recognition in 2000 of a $6.7
million after-tax reserve revenue adjustment and resulting
increase to income relating to certain regulatory proceedings,
as previously discussed.  Higher natural gas transportation
volumes combined with higher average transportation rates and
increased gathering volumes at the pipeline also partially
offset the earnings decline.  The increase in energy services
revenue and the related increase in purchased natural gas sold
resulted from significantly higher natural gas prices and
increased volumes.

Natural Gas and Oil Production

    Natural gas and oil production earnings increased
primarily due to significantly higher realized natural gas and
oil prices.  Higher natural gas and oil production due to
acquisitions since the comparable period in 1999 and ongoing
development of existing properties, along with increased other
revenue due to higher sales of inventoried natural gas, added
to the earnings increase.  Partially offsetting the earnings
improvement were increased depreciation, depletion and
amortization expense, due to higher production volumes and
higher rates, and increased operation and maintenance expense,
mainly from higher lease operating expenses and higher general
and administrative costs due primarily to acquisitions, and
increased maintenance on existing properties.  Increased
interest expense due to higher average borrowings and interest
rates also partially offset the earnings increase.  Hedging
activities for natural gas and oil production for 2000
resulted in realized prices that were 87 percent and
82 percent, respectively, of what otherwise would have been
received.

Construction Materials and Mining

    Construction materials and mining earnings increased largely
due to the absence in 2000 of $5.6 million in after-tax charges
to earnings in 1999, the result of the resolution of the coal
arbitration proceeding.  Higher earnings at the construction
materials operations as a result of earnings from businesses
acquired since the comparable period in 1999, higher aggregate,
ready-mixed concrete and cement volumes at existing operations
and a gain of $1.2 million after-tax on the sale of a
nonstrategic property also added to the earnings improvement.
Increased interest expense resulting from higher acquisition-
related borrowings, higher selling, general and administrative
costs, higher energy costs and increased depreciation, depletion
and amortization expense due to increased aggregate volumes and
increased plant balances, partially offset the earnings
improvement at the construction materials operations.

Safe Harbor for Forward-looking Statements

    The company is including the following cautionary statement
in this Form 10-K to make applicable and to take advantage of the
safe harbor provisions of the Private Securities Litigation
Reform Act of 1995 for any forward-looking statements made by, or
on behalf of, the company.  Forward-looking statements include
statements concerning plans, objectives, goals, strategies,
future events or performance, and underlying assumptions (many of
which are based, in turn, upon further assumptions) and other
statements which are other than statements of historical facts.
From time to time, the company may publish or otherwise make
available forward-looking statements of this nature, including
statements contained within Prospective Information.  All such
subsequent forward-looking statements, whether written or oral
and whether made by or on behalf of the company, are also
expressly qualified by these cautionary statements.

    Forward-looking statements involve risks and uncertainties,
which could cause actual results or outcomes to differ materially
from those expressed.  The company's expectations, beliefs and
projections are expressed in good faith and are believed by the
company to have a reasonable basis, including without limitation
management's examination of historical operating trends, data
contained in the company's records and other data available from
third parties, but there can be no assurance that the company's
expectations, beliefs or projections will be achieved or
accomplished.  Furthermore, any forward-looking statement speaks
only as of the date on which such statement is made, and the
company undertakes no obligation to update any forward-looking
statement or statements to reflect events or circumstances that
occur after the date on which such statement is made or to
reflect the occurrence of unanticipated events.  New factors
emerge from time to time, and it is not possible for management
to predict all of such factors, nor can it assess the effect of
each such factor on the company's business or the extent to which
any such factor, or combination of factors, may cause actual
results to differ materially from those contained in any forward-
looking statement.

    In addition to other factors and matters discussed elsewhere
herein, some important factors that could cause actual results or
outcomes for the company to differ materially from those
discussed in forward-looking statements include prevailing
governmental policies and regulatory actions with respect to
allowed rates of return, financings, or industry and rate
structures, acquisition and disposal of assets or facilities,
operation and construction of plant facilities, recovery of
purchased power and purchased gas costs, present or prospective
generation and availability of economic supplies of natural gas.
Other important factors include the level of governmental
expenditures on public projects and the timing of such projects,
changes in anticipated tourism levels, the effects of competition
(including but not limited to electric retail wheeling and
transmission costs and prices of alternate fuels and system
deliverability costs), natural gas and oil commodity prices,
drilling successes in natural gas and oil operations, the ability
to contract for or to secure necessary drilling rig contracts and
to retain employees to drill for and develop reserves, ability to
acquire natural gas and oil properties, the availability of
economic expansion or development opportunities, and political,
regulatory and economic conditions and changes in currency rates
in foreign countries where the company does business.

    The business and profitability of the company are also
influenced by economic and geographic factors, including
political and economic risks, economic disruptions caused by
terrorist activities, changes in and compliance with
environmental and safety laws and policies, weather conditions,
population growth rates and demographic patterns, market demand
for energy from plants or facilities, changes in tax rates or
policies, unanticipated project delays or changes in project
costs, unanticipated changes in operating expenses or capital
expenditures, labor negotiations or disputes, changes in credit
ratings or capital market conditions, inflation rates, inability
of the various counterparties to meet their contractual
obligations, changes in accounting principles and/or the
application of such principles to the company, changes in
technology and legal proceedings, and the ability to effectively
integrate the operations of acquired companies.

Prospective Information

    The following information includes highlights of the key
growth strategies, projections and certain assumptions for the
company over the next few years and other matters for the company
for each of its six business segments.  Many of these highlighted
points are forward-looking statements.  There is no assurance
that the company's projections, including estimates for growth
and increases in revenues and earnings, will in fact be achieved.
Reference should be made to assumptions contained in this section
as well as the various important factors listed under the heading
Safe Harbor for Forward-looking Statements.  Changes in such
assumptions and factors could cause actual future results to
differ materially from the company's targeted growth, revenue and
earnings projections.

MDU Resources Group, Inc.

- - Earnings per share, diluted, for 2002 are projected in the
  $2.05 to $2.30 range.  Excluding the benefit of the compromise
  agreement discussed in Note 18 of Notes to Consolidated Financial
  Statements, earnings per share from operations are projected to
  be in the approximate range of $1.85 to $2.10.

- - The company expects the percentage of 2002 earnings per
  share from operations, excluding the benefit of the compromise
  agreement, by quarter to be in the following approximate ranges:

  -    First Quarter:  10 to 15 percent
  -    Second Quarter: 20 to 25 percent
  -    Third Quarter:  35 to 40 percent
  -    Fourth Quarter: 25 to 30 percent

- - The company's long-term growth goals on compound annual
  earnings per share from operations are in the range of 10 percent
  to 12 percent.  However, the general weakening of the economy has
  added uncertainty in the ability of the company to achieve this
  goal particularly in the early years of the planning cycle.

- - The company expects to issue and sell equity from time to
  time to keep its debt at the nonregulated businesses at no more
  than 40 percent of total capitalization.

- - The company estimates that the benefit resulting solely from
  the discontinuance of goodwill amortization would be 5 to 6 cents
  per common share in 2002.

Electric

- - Montana-Dakota has obtained and holds valid and existing
  franchises authorizing it to conduct its electric and natural gas
  operations in all of the municipalities it serves where such
  franchises are required.  As franchises expire, Montana-Dakota
  may face increasing competition in its service areas,
  particularly its service to smaller towns, from rural electric
  cooperatives.  Montana-Dakota intends to protect its service area
  and seek renewal of all expiring franchises and will continue to
  take steps to effectively operate in an increasingly competitive
  environment.

- - The North Dakota Public Service Commission (NDPSC) has
  authorized its Staff to initiate an investigation into the
  earnings levels of Montana-Dakota's North Dakota electric
  operations based on Montana-Dakota's 2000 Annual Report to the
  NDPSC.  The investigation is based on a complaint filed with the
  NDPSC on September 7, 2001, by the Staff.  The complaint alleges
  that Montana-Dakota's annual revenues should be reduced by $9.2
  million, or approximately 11 percent, due to the company earning
  above its authorized rate of return.  The company is unable to
  predict the outcome of the investigation at this time, but does
  not expect the final resolution to be material to its results of
  operations.

- - Due to growing electric demand, a 40-megawatt gas turbine
  power plant may be added in the three to five year planning
  horizon.

- - Currently, the company is working with the state of North
  Dakota to determine the feasibility of constructing a 500-
  megawatt lignite-fired power plant in western North Dakota.  The
  first preliminary decision is expected in December 2002.

Natural gas distribution

- - Annual natural gas throughput for 2002 is expected to be
  approximately 58 million decatherms, with about 40 million
  decatherms from sales and 18 million decatherms from
  transportation.

Utility services

- - Revenues for this segment are expected to exceed $500
  million in 2002.

- - This segment's goal is to achieve compound annual revenue
  and earnings growth rates of approximately 20 percent to 25
  percent over the next five years.  However, the general weakening
  of the economy has added uncertainty in the ability of the
  company to achieve this goal particularly in the early years of
  the planning cycle.

Pipeline and energy services

- - In 2002, natural gas throughput from this segment, including
  both transportation and gathering, is expected to increase by
  approximately 10 percent.

- - A 247-mile pipeline to transport additional gas to market
  and enhance the use of the company's storage facilities is
  currently under regulatory review.  Depending upon the timing of
  the receipt of the necessary regulatory approval, construction
  completion could occur as early as late 2002 to mid-2003.

- - The company continues to pursue electric generation
  opportunities in Brazil.  These projects are targeted toward a
  niche market where the company expects to provide energy on a
  contract basis in order to reduce risk.  The first project, a 200-
  megawatt natural gas-fired generating facility, is planned to
  begin production during the second quarter of 2002.

- - On February 5, 2002, Centennial Power, Inc., an indirect
  wholly owned subsidiary of the company, announced the acquisition
  of Rocky Mountain Power, Inc.  The acquisition enables the
  company to construct a 113-megawatt, coal-fired electric
  generation facility (Plant) near Hardin, Montana.  The Plant is
  expected to enter commercial operation in 2003.

Natural gas and oil production

- - Combined natural gas and oil production at this segment is
  expected to be approximately 30 percent higher in 2002 than in
  2001.

- - Natural gas prices in the Rocky Mountain region for February
  through December 2002, reflected in the company's 2002 earnings
  estimates, are in the range of $2.25 to $2.75 per Mcf.  The
  company's estimates for natural gas prices on the NYMEX for
  February through December 2002, reflected in the company's 2002
  earnings estimates, are in the range of $2.75 to $3.25 per Mcf.
  During 2001, more than half of this segment's natural gas
  production was priced using Rocky Mountain prices.

- - NYMEX crude oil prices, reflected in the company's 2002
  earnings estimates, are in the range of $20 to $24 per barrel for
  2002.

- - This segment has hedged a portion of its 2002 production.
  The company has entered into a swap agreement and fixed price
  forward sales representing approximately 10 percent to 15 percent
  of 2002 estimated annual natural gas production.  The natural gas
  swap is at an average NYMEX price of $4.34 per Mcf.  The company
  has also entered into oil swap agreements at average NYMEX prices
  in the range of $24.80 to $25.25 per barrel, representing
  approximately 20 percent to 25 percent of the company's 2002
  estimated annual oil production.

Construction materials and mining

- - Excluding the effects of potential future acquisitions,
  aggregate volumes are expected to increase by approximately 5
  percent to 10 percent in 2002 and asphalt and ready-mixed
  concrete volumes are expected to remain high at levels comparable
  to 2001.

- - This segment's goal is to achieve compound annual revenue
  and earnings growth rates of approximately 10 percent to 20
  percent over the next five years.  However, the general weakening
  of the economy has added uncertainty in the ability of the
  company to achieve this goal particularly in the early years of
  the planning cycle.

New Accounting Pronouncements

    In June 2001, the Financial Accounting Standards Board (FASB)
approved Statement of Financial Accounting Standards No. 141,
"Business Combinations"(SFAS No. 141), Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible
Assets" (SFAS No. 142), and Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations"
(SFAS No. 143).  In August 2001, the FASB approved Statement of
Financial Accounting Standards No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144).  For
further information on SFAS No. 141, SFAS No. 142, SFAS No. 143
and SFAS No. 144, see Note 1 of Notes to Consolidated Financial
Statements.

Critical Accounting Policies

    The company has prepared its financial statements in
conformity with accounting principles generally accepted in the
United States, and these statements necessarily include some
amounts that are based on informed judgments and estimates of
management.  The company's significant accounting policies are
discussed in Note 1 of Notes to Consolidated Financial
Statements.  The company's critical accounting policies are
subject to judgments and uncertainties which affect the
application of such policies.  As discussed below the company's
financial position or results of operations may be materially
different when reported under different conditions or when using
different assumptions in the application of such policies.  In
the event estimates or assumptions prove to be different from
actual amounts, adjustments are made in subsequent periods to
reflect more current information.  The company's critical
accounting policies include:

Impairment of long-lived assets and intangibles

    The company reviews the carrying values of its long-lived
assets, including goodwill and identifiable intangibles, whenever
events or changes in circumstances indicate that such carrying
values may not be recoverable and annually for goodwill as
required by SFAS No. 142.  Unforeseen events and changes in
circumstances and market conditions and material differences in
the value of intangible assets due to changes in estimates of
future cash flows could negatively affect the fair value of the
company's assets and result in an impairment charge.  Fair value
is the amount at which the asset could be bought or sold in a
current transaction between willing parties and may be estimated
using a number of techniques, including quoted market prices or
valuations by third parties, present value techniques based on
estimates of cash flows, or multiples of earnings or revenues
performance measures.  The fair value of the asset could be
different using different estimates and assumptions in these
valuation techniques.

Impairment testing of natural gas and oil properties

    The company uses the full-cost method of accounting for its
natural gas and oil production activities as discussed in Note 1
of Notes to Consolidated Financial Statements.  The full-cost
method of accounting requires judgments and uncertainties
including specific point in time natural gas and oil prices used
for valuing reserves and estimates of reserves.  Sustained
downward movements in natural gas and oil prices and changes in
estimates of reserve quantities could result in a future write-
down of the company's natural gas and oil properties.

Revenue recognition

    Revenue is recognized when the earnings process is complete,
as evidenced by an agreement between the customer and the
company, when delivery has occurred or services have been
rendered, when the fee is fixed or determinable and when
collection is probable.  The company's revenue recognition policy
is discussed in Note 1 of Notes to Consolidated Financial
Statements.  The recognition of revenue in conformity with
accounting principles generally accepted in the United States
requires the company to make estimates and assumptions that
affect the reported amounts of revenue.  Estimates related to the
recognition of revenue include the accumulated provision for
revenues subject to refund, natural gas and oil revenues and
costs on construction contracts under the percentage-of-
completion method.  As additional information becomes available,
or actual amounts are determinable, the recorded estimates are
revised.  Consequently, operating results can be affected by
revisions to prior accounting estimates.

Derivatives

    The company has cash flow hedging instruments comprised of
natural gas and oil price swap agreements.  The company accounts
for its cash flow hedges in accordance with Statement of
Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS No. 133),
amended by Statement of Financial Accounting Standards No. 137,
"Accounting for Derivative Instruments and Hedging Activities -
Deferral of the Effective Date of FASB Statement No. 133" and
Statement of Financial Accounting Standards No. 138, "Accounting
for Certain Derivative Instruments and Certain Hedging
Activities" (all such statements hereinafter referred to as SFAS
No. 133) and records the fair value of the instruments on the
balance sheet.  The objective for holding the natural gas and oil
price swap agreements is to manage a portion of the market risk
associated with fluctuations in the price of natural gas and oil
on the company's forecasted sale of natural gas and oil
production.  For more information on the company's derivative
instruments see Note 3 of Notes to Consolidated Financial
Statements.  Material changes to the company's results of
operations could occur if the hedging instrument is not highly
effective in achieving offsetting cash flows attributable to the
hedged risk.  The fair value of the derivative instruments is
based on valuations determined by the counterparties.  Changes in
counterparty valuation assumptions and estimates could cause a
material effect on the company's financial position or results of
operations.

Purchase accounting

    The company accounts for its acquisitions under the purchase
method of accounting and accordingly, the acquired assets and
liabilities assumed are recorded at their respective fair values.
The recorded values of assets and liabilities are based on third-
party estimates and valuations when available.  The remaining
values are based on management's judgments and estimates, and
accordingly, the company's financial position or results of
operations may be affected by changes in estimates and judgments.

Accounting for the effects of regulation

    Substantially all of the company's regulatory assets, other
than certain deferred income taxes, are being reflected in rates
charged to customers in accordance with Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of
Regulation" (SFAS No. 71).  If, for any reason, the company's
regulated businesses cease to meet the criteria for application
of SFAS No. 71 for all or part of their operations, the
regulatory assets and liabilities relating to those portions
ceasing to meet such criteria would be removed from the balance
sheet and included in the statement of income as an extraordinary
item in the period in which the discontinuance of SFAS No. 71
occurs.  Consequently, the discontinuance of SFAS No. 71 could
have a material effect on the company's results of operations.

Liquidity and Capital Commitments

Cash flows

Operating activities --

    Cash flows from operating activities in 2001 increased
$141.6 million compared to 2000, primarily due to an increase in
net income of $44.8 million, and higher depreciation, depletion
and amortization expense of $29.0 million, largely the result of
increased acquisition-related property, plant and equipment
balances.  Also adding to the increase in operating cash flows
was the increase in cash from changes in working capital items of
$95.9 million.  This increase was primarily due to the sale of
certain energy services operations and lower natural gas prices.

    In 2000, cash flows from operating activities increased
$52.1 million compared to 1999, primarily due to an increase in
net income of $26.9 million, and higher depreciation, depletion
and amortization expense of $29.1 million, largely the result of
increased acquisition-related property, plant and equipment
balances.  Also adding to the increase in operating cash flows
was an increase in deferred income taxes of $20.8 million.
Offsetting these increases in cash flows was an increase in the
cash used in working capital items of $27.7 million, which was
primarily caused by increased natural gas prices and higher
natural gas marketing sales.

Investing activities --

    Cash flows used in investing activities in 2001 decreased
$49.0 million compared to 2000, primarily the result of a
decrease in net capital expenditures of $67.2 million, partially
offset by an increase in notes receivables of $18.8 million.  Net
capital expenditures exclude the following noncash transactions
related to acquisitions: issuance of the company's equity
securities in 2001 and 2000 and the conversion of a note
receivable to purchase consideration in 2000.

    The cash flows used in investing activities in 2000 increased
$208.2 million compared to 1999, largely the result of an
increase of $244.0 million in net capital expenditures, slightly
offset by a decrease in notes receivables of $30.9 million.  Net
capital expenditures exclude the following noncash transactions
related to acquisitions: issuance of the company's equity
securities in 2000 and 1999 and the conversion of a note
receivable to purchase consideration in 2000.

Financing activities --

    Financing activities resulted in a decrease in cash flows
for 2001 of $144.3 million compared to 2000.  This decrease was
largely due to the increase of the repayment of long-term debt of
$85.7 million, and the decrease of the issuance of long-term debt
of $69.9 million.  Partially offsetting the decrease was an
increase in proceeds from issuance of common stock of $19.9
million.

    Financing activities resulted in an increase in cash flows
for 2000 of $76.8 million compared to 1999.  This increase
resulted primarily from an increase in proceeds from issuance of
common stock of $44.1 million and an increase in the issuance of
long-term debt of $37.6 million.  This increase was partially
offset by an increase in the repayment of long-term debt of $10.6
million.

Capital expenditures

    The company's capital expenditures (in millions) for 1999
through 2001 and as anticipated for 2002 through 2004 are
summarized in the following table, which also includes the
company's capital needs for the retirement of maturing long-term
debt and preferred stock.

        Actual                                             Estimated*
  1999    2000    2001  Capital expenditures:         2002    2003    2004
$ 18.2  $ 15.8  $ 14.4   Electric                   $ 19.8  $ 21.7  $ 34.2
   9.2    21.3    14.7   Natural gas distribution     10.0    14.2    10.4
  16.1    42.6    70.2   Utility services             68.6    68.2    70.7
                         Pipeline and energy
  35.1    69.0    51.0    services                   169.9   125.1   102.5
                         Natural gas and oil
  64.3   173.5   118.7    production                 122.3   122.6   129.2
                         Construction materials
 105.1   218.7   170.6    and mining                 154.1    90.8   132.0
 248.0   540.9   439.6                               544.7   442.6   479.0
                        Net proceeds from sale or
 (16.6)  (11.0)  (51.6)  disposition of property      (2.7)   (2.2)   (1.1)
 231.4   529.9   388.0  Net capital expenditures     542.0   440.4   477.9

                        Retirement of long-term
  18.8    29.4   115.2   debt and preferred stock     11.2   266.9    22.0
$250.2  $559.3  $503.2                              $553.2  $707.3  $499.9

*The estimated 2002 through 2004 capital expenditures reflected
 in the above table include potential future acquisitions.  The
 company continues to evaluate potential future acquisitions;
 however, these acquisitions are dependent upon the availability
 of economic opportunities and, as a result, actual acquisitions
 and capital expenditures may vary significantly from the above
 estimates.

    Capital expenditures for 2001, 2000 and 1999, related to
acquisitions, in the preceding table include the following
noncash transactions: issuance of the company's equity securities
of $57.4 million in 2001; issuance of the company's equity
securities and the conversion of a note receivable to purchase
consideration of $132.1 million in 2000; and issuance of the
company's equity securities of $77.5 million in 1999.

    In 2001, the company acquired a number of businesses, none
of which was individually material, including construction
materials and mining businesses in Hawaii, Minnesota and Oregon;
utility services businesses in Missouri and Oregon; and an energy
services company specializing in cable and pipeline locating and
tracking systems.  The total purchase consideration for these
businesses, consisting of the company's common stock and cash,
was $170.1 million.

    The 2001 capital expenditures, including those for the
previously mentioned acquisitions, and retirements of long-term
debt and preferred stock, were met from internal sources, the
issuance of long-term debt and the company's equity securities.
Capital expenditures for the years 2002 through 2004 include
those for system upgrades, routine replacements, service
extensions, routine equipment maintenance and replacements, land
and building improvements, pipeline and gathering expansion
projects, the further enhancement of natural gas and oil
production and reserve growth, power generation opportunities and
for potential future acquisitions and other growth opportunities.
The company continues to evaluate potential future acquisitions
and other growth opportunities; however, they are dependent upon
the availability of economic opportunities and, as a result,
actual acquisitions and capital expenditures may vary
significantly from the estimates in the preceding table.  It is
anticipated that all of the funds required for capital
expenditures and retirements of long-term debt and preferred
stock for the years 2002 through 2004 will be met from various
sources. These sources include internally generated funds, the
company's $40 million revolving credit and term loan agreement, a
commercial paper credit facility at Centennial, as described
below, and through the issuance of long-term debt and the
company's equity securities.  At December 31, 2001, $25.0 million
under the revolving credit and term loan agreement was
outstanding.

Capital resources

    Centennial has a revolving credit agreement (Centennial
credit agreement) with various banks that supports Centennial's
$350 million commercial paper program (Centennial commercial
paper program).  There were no outstanding borrowings under the
Centennial credit agreement at December 31, 2001.  Under the
Centennial commercial paper program, $219.7 million was
outstanding at December 31, 2001.  The Centennial commercial
paper borrowings are classified as long term as Centennial
intends to refinance these borrowings on a long-term basis
through continued Centennial commercial paper borrowings and as
further supported by the Centennial credit agreement, which
allows for subsequent borrowings up to a term of one year.
Centennial intends to renew the Centennial credit agreement,
which expires September 27, 2002, on an annual basis.

    Centennial has an uncommitted long-term master shelf
agreement that allows for borrowings of up to $300 million.
Under the master shelf agreement, $210 million was outstanding at
December 31, 2001.

    MDU International has a credit agreement, which expires on
June 30, 2002, that allows for borrowings up to $50 million.
There were no outstanding borrowings under this credit agreement
at December 31, 2001.

    The company has unsecured short-term lines of credit from a
number of banks totaling $60 million that allow the company to
borrow under the lines and/or provide credit support for the
company's commercial paper program.  There were no outstanding
borrowings under the company's lines of credit or the company's
commercial paper program at December 31, 2001.  The company
intends to renew these lines of credit on an annual basis.

    On December 31, 2001, the company reported the sale of
189,689 shares of the company's common stock to Ensign Peak
Advisors, Inc. (Ensign) and 379,376 shares of the company's
common stock to Carlson Capital, L.P. (Carlson), pursuant to
purchase agreements by and between the company and Ensign and
Carlson.  The company received total proceeds from these sales of
$15 million.  These proceeds were used for refunding outstanding
debt obligations.

    The company's goal is to maintain acceptable credit ratings
under its credit agreements and individual bank lines of credit
in order to access the capital markets through the issuance of
commercial paper.  If the company were to experience a minor
downgrade of its credit rating, the company would not anticipate
any change in its ability to access the capital markets.
However, in such event, the company would expect a nominal basis
point increase in overall interest rates with respect to its cost
of borrowings.  If the company were to experience a significant
downgrade of its credit ratings, which the company does not
currently anticipate, it may need to borrow under its committed
bank lines.

    Borrowing under its committed bank lines would be expected
to increase annualized interest expense on its variable rate debt
by approximately $1 million (after-tax) for the calendar year
2002 based on December 31, 2001 variable rate borrowings.  Based
on the company's overall interest rate exposure at December 31,
2001, this change would not have a material affect on the
company's results of operations.

    On an annual basis, the company negotiates the placement of
the Centennial credit agreement and its individual bank lines of
credit that provide credit support to access the capital markets.
In the event the company were unable to successfully negotiate
the bank credit facilities, or in the event the fees on such
facilities became too expensive, which the company does not
currently anticipate, the company would seek alternative funding.
One source of alternative funding might involve the
securitization of certain company assets.

    In order to borrow under the company's credit facilities,
the company must be in compliance with the applicable covenants
and certain other conditions.  The company is in compliance with
these covenants and meets the required conditions at December 31,
2001.  In the event the company does not comply with the
applicable covenants and other conditions, the company may need
to pursue alternative sources of funding as previously discussed.

    The company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of
its Indenture of Mortgage.  Generally, those restrictions require
the company to pledge $1.43 of unfunded property to the Trustee
for each dollar of indebtedness incurred under the Indenture and
that annual earnings (pretax and before interest charges), as
defined in the Indenture, equal at least two times its annualized
first mortgage bond interest costs.  Under the more restrictive
of the two tests, as of December 31, 2001, the company could have
issued approximately $305 million of additional first mortgage
bonds.

    The company's coverage of fixed charges including preferred
dividends was 5.3 times and 4.1 times for 2001 and 2000,
respectively.  Additionally, the company's first mortgage bond
interest coverage was 8.5 times in 2001 compared to 8.3 times in
2000.  Common stockholders' equity as a percent of total
capitalization was 58 percent and 54 percent at December 31, 2001
and 2000, respectively.

Contractual obligations and commercial commitments

    For more information on the company's contractual
obligations on long-term debt, operating leases and purchase
commitments, see Notes 6 and 15 of Notes to Consolidated
Financial Statements.  At December 31, 2001, the company's
commitments under these obligations were as follows:


                    2002    2003    2004    2005    2006  Thereafter    Total
                                    (In millions)

Long-term debt    $ 11.1  $266.8   $21.9  $ 70.2  $ 85.2      $339.6 $  794.8
Operating leases    17.4    14.3    11.0     8.3     6.3        25.1     82.4
Purchase
  commitments      108.8    53.1    46.9    39.2    33.2       126.5    407.7

                  $137.3  $334.2   $79.8  $117.7  $124.7      $491.2 $1,284.9

    The company has certain financial guarantees outstanding at
December 31, 2001.  These consisted largely of guarantees on
obligations and loans on the natural gas-fired power plant
project in the Brazilian state of Ceara.  For more information on
these guarantees, see Notes 10 and 15 of Notes to Consolidated
Financial Statements.  These guarantees as of December 31, 2001,
are approximately $20.6 million for 2002.

Effects of Inflation

    Inflation did not have a significant effect on the company's
operations in 2001, 2000 or 1999.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

    The company is exposed to the impact of market fluctuations
associated with commodity prices and interest rates.  The company
has policies and procedures to assist in controlling these market
risks and utilizes derivatives to manage a portion of its risk.

Commodity price risk --

    The company utilizes natural gas and oil price swap
agreements to manage a portion of the market risk associated with
fluctuations in the price of natural gas and oil on the company's
forecasted sales of natural gas and oil production.

    The company's policy allows the use of derivative instruments
as part of an overall energy price management program to
efficiently manage and minimize commodity price risk.  The
company's policy prohibits the use of derivative instruments for
speculating to take advantage of market trends and conditions and
the company has procedures in place to monitor compliance with
its policies.  The company is exposed to credit-related losses in
relation to hedged derivative instruments in the event of
nonperformance by counterparties.  The company has policies and
procedures, which management believes minimize credit-risk
exposure.  These policies and procedures include an evaluation of
potential counterparties' credit ratings, credit exposure
limitations and settlement of natural gas and oil price swap
agreements monthly.  Accordingly, the company does not anticipate
any material effect to its financial position or results of
operations as a result of nonperformance by counterparties.

    Upon the adoption of SFAS No. 133, the company recorded the
fair market value of the natural gas and oil price swap
agreements on the company's Consolidated Balance Sheets.  On an
ongoing basis, the company adjusts its balance sheet to reflect
the current fair market value of its swap agreements.  The
related gains or losses on these agreements are recorded in
common stockholders' equity as a component of other comprehensive
income (loss).  At the date the underlying transaction occurs,
the amounts accumulated in other comprehensive income (loss) are
reported in the Consolidated Statements of Income.  To the extent
that the hedges are not effective, the ineffective portion of the
changes in fair market value is recorded directly in earnings.

    The following table summarizes hedge agreements entered into
by certain wholly owned subsidiaries of the company, as of
December 31, 2001.  These agreements call for the subsidiaries to
receive fixed prices and pay variable prices.

                     (Notional amount and fair value in thousands)

                             Weighted
                             Average      Notional
                           Fixed Price     Amount
                           (Per MMBtu)  (In MMBtu's)   Fair Value

   Natural gas swap
    agreement maturing
    in 2002                  $  4.34        1,150          $1,878


                             Weighted
                             Average      Notional
                           Fixed Price     Amount
                           (Per barrel) (In barrels)   Fair Value

   Oil swap agreements
    maturing in 2002         $ 24.96          405          $1,789


   The following table summarizes hedge agreements entered into
by certain wholly owned subsidiaries of the company, as of
December 31, 2000.  These agreements call for the subsidiaries to
receive fixed prices and pay variable prices.

                     (Notional amount and fair value in thousands)

                             Weighted
                             Average      Notional
                           Fixed Price     Amount
                           (Per MMBtu)  (In MMBtu's)   Fair Value

   Natural gas swap
    agreements maturing
    in 2001                  $ 4.45         5,461       $ (12,311)


                             Weighted
                             Average      Notional
                           Fixed Price     Amount
                           (Per barrel) (In barrels)   Fair Value

   Oil swap agreements
    maturing in 2001         $28.80           593        $  2,261


    In the event a derivative instrument does not qualify for
hedge accounting because it is no longer highly effective in
offsetting changes in cash flows of a hedged item; or if the
derivative instrument expires or is sold, terminated, or
exercised; or if management determines that designation of the
derivative instrument as a hedge instrument is no longer
appropriate, hedge accounting will be discontinued, and the
derivative instrument would continue to be carried at fair value
with changes in its fair value recognized in earnings.  In these
circumstances, the net gain or loss at the time of discontinuance
of hedge accounting would remain in other comprehensive income
(loss) until the period or periods during which the hedged
forecasted transaction affects earnings, at which time the net
gain or loss would be reclassified into earnings.  In the event a
cash flow hedge is discontinued because it is unlikely that a
forecasted transaction will occur, the derivative instrument
would continue to be carried on the balance sheet at its fair
value, and gains and losses that were accumulated in other
comprehensive income (loss) would be recognized immediately in
earnings.  The company's policy requires approval to terminate a
hedge agreement prior to its original maturity.

Interest rate risk --

    The company uses fixed and variable rate long-term debt to
partially finance capital expenditures and mandatory debt
retirements.  These debt agreements expose the company to market
risk related to changes in interest rates.  The company manages
this risk by taking advantage of market conditions when timing
the placement of long-term or permanent financing.  The company
has also historically used interest rate swap agreements to
manage a portion of the company's interest rate risk and may take
advantage of such agreements in the future to minimize such risk.
The company also has outstanding 14,000 shares of 5.10% Series
preferred stock subject to mandatory redemption as of December
31, 2001.  The company is obligated to make annual sinking fund
contributions to retire the preferred stock and pay cumulative
preferred dividends at a fixed rate of 5.10 percent.  The table
below shows the amount of debt, including current portion, and
related weighted average interest rates, by expected maturity
dates and the aggregate annual sinking fund amount applicable to
preferred stock subject to mandatory redemption and the related
dividend rate, as of December 31, 2001.  Weighted average
variable rates are based on forward rates as of December 31,
2001.
<TABLE>
<CAPTION>
                                                                                Fair
                        2002    2003   2004   2005   2006  Thereafter  Total   Value
                                        (Dollars in millions)
<S>                    <C>    <C>     <C>    <C>    <C>      <C>      <C>     <C>
Long-term debt:
  Fixed rate           $11.1  $ 47.3  $21.9  $70.2  $85.2    $339.6   $575.3  $672.3
  Weighted average
    interest rate        7.2%    6.0%   6.6%   8.0%   6.5%      7.5%     7.2%      -

   Variable rate           -  $219.5      -      -      -         -   $219.5  $222.4
   Weighted average
    interest rate          -     2.4%     -      -      -         -      2.4%      -

 Preferred stock
  subject to mandatory
  redemption           $  .1  $   .1  $  .1  $  .1  $  .1    $   .9   $  1.4  $   .9
 Dividend rate           5.1%    5.1%   5.1%   5.1%   5.1%      5.1%     5.1%      -
</TABLE>

    For further information on derivative instruments and fair
value of other financial instruments, see Notes 3 and 4 of Notes
to Consolidated Financial Statements.

Foreign currency risk --

    The company has an investment in a Brazilian project as
discussed in Note 10 of Notes to Consolidated Financial
Statements.  This project involves foreign currency exchange rate
risk.  The company intends to manage this risk through a variety
of risk mitigation measures, including specific contractual
provisions and currency hedging.  As of December 31, 2001, the
company does not believe it had a material exposure to foreign
currency risk attributable to this investment.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

    Reference is made to Pages 33 through 61 of the company's
Annual Report, which is incorporated herein by reference.

ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE

    Reference is made to Page 32 of the company's Annual Report,
which is incorporated herein by reference.


                         PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

    Reference is made to Pages 2 through 6 and 16 through 17 of
the company's Proxy Statement dated March 8, 2002 (Proxy
Statement), which is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

    Reference is made to Pages 8 through 13 and 19 of the Proxy
Statement, which is incorporated herein by reference with the
exception of the compensation committee report on executive
compensation.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
         MANAGEMENT

    Reference is made to Page 18 of the Proxy Statement, which is
incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

    None.

                             PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
         FORM 8-K

(a) Financial Statements, Financial Statement Schedules and
    Exhibits.

    Index to Financial Statements and Financial Statement
    Schedules
                                                           Page
    1.  Financial Statements:

        Report of Independent Public Accountants            *
        Consolidated Statements of Income for each
          of the three years in the period ended
          December 31, 2001                                 *
        Consolidated Balance Sheets at December 31,
          2001 and 2000                                     *
        Consolidated Statements of Common Stockholders'
          Equity for each of the three years in the
          period ended December 31, 2001                    *
        Consolidated Statements of Cash Flows for
          each of the three years in the period ended
          December 31, 2001                                 *
        Notes to Consolidated Financial Statements          *

    2.  Financial Statement Schedules:
        Report of Independent Public Accountants on
          Financial Statement Schedule                      **
        Schedule II - Consolidated Valuation and
          Qualifying Accounts for the Years Ended
          December 31, 2001, 2000 and 1999                  **

        All other schedules are omitted
        because of the absence of the conditions
        under which they are required, or because
        the information required is included in the
        company's Consolidated Financial Statements
        and Notes thereto.

 *  The Consolidated Financial Statements listed in the above
    index which are included in the company's Annual Report to
    Stockholders for 2001 are hereby incorporated by reference.
    With the exception of the pages referred to in Items 6, 8
    and 9, the company's Annual Report to Stockholders for 2001
    is not to be deemed filed as part of this report.

**  Filed herewith.

3.  Exhibits:
         3(a)  Restated Certificate of Incorporation of
               the company, as amended to date, filed as
               Exhibit 3(a) to Form 10-Q for the quarter
               ended June 30, 1999, in File No. 1-3480      *
         3(b)  By-laws of the company, as amended to date,
               filed as Exhibit 4(b) to Form S-8 on
               October 1, 2001, in Registration
               No. 333-70622                                *
         4(a)  Indenture of Mortgage, dated as of May 1,
               1939, as restated in the Forty-Fifth
               Supplemental Indenture, dated as of
               April 21, 1992, and the Forty-Sixth
               through Forty-Ninth Supplements thereto
               between the company and the New York Trust
               Company (The Bank of New York, successor
               Corporate Trustee) and A. C. Downing
               (Douglas J. MacInnes, successor Co-Trustee),
               filed as Exhibit 4(a) in Registration
               No. 33-66682; and Exhibits 4(e), 4(f)
               and 4(g) in Registration No. 33-53896;
               and Exhibit 4(c)(i) in Registration
               No. 333-49472                                *
         4(b)  Rights agreement, dated as of November 12,
               1998, between the company and Wells Fargo
               Bank Minnesota, N.A. (formerly known as
               Norwest Bank Minnesota, N.A.), Rights
               Agent, filed as Exhibit 4.1 to Form 8-A on
               November 12, 1998, in File No. 1-3480        *
      + 10(a)  Executive Incentive Compensation Plan,
               as amended to date                           **
      + 10(b)  1992 Key Employee Stock Option Plan, as
               amended to date, filed as Exhibit 10(a) to
               Form 10-Q for the quarter ended June 30,
               2000 in File No. 1-3480                      *
      + 10(c)  Supplemental Income Security Plan, as
               amended to date, filed as Exhibit 10(d) to
               Form 10-K for the year ended December 31,
               1996, in File No. 1-3480                     *
      + 10(d)  Directors' Compensation Policy, as amended
               to date                                      **
      + 10(e)  Deferred Compensation Plan for Directors,
               as amended to date                           **
      + 10(f)  Non-Employee Director Stock Compensation
               Plan, as amended to date                     **
      + 10(g)  1997 Non-Employee Director Long-Term
               Incentive Plan, as amended to date, filed
               as Exhibit 10(d) to Form 10-Q for the quarter
               ended June 30, 2000, in File No. 1-3480      *
      + 10(h)  1997 Executive Long-Term Incentive Plan,
               as amended to date, filed as Exhibit 10(a)
               to Form 10-Q for the quarter ended
               March 31, 2001, in File No. 1-3480           *
        12     Computation of Ratio of Earnings to Fixed
               Charges and Combined Fixed Charges and
               Preferred Stock Dividends                    **
        13     Selected financial data, financial
               statements, supplementary data and
               Change in Accountants as contained in the
               Annual Report to Stockholders for 2001;
               Report of Independent Public Accountants on
               Financial Statement Schedule; and Financial
               Statement Schedule II                        **
        16     Letter from Arthur Andersen LLP to the
               Securities and Exchange Commission
               regarding change in accountants, filed as
               Exhibit 16 to Form 8-K on February 20,
               2002, in File No. 1-3480                     *
        21     Subsidiaries of MDU Resources Group, Inc.    **
        23     Consent of Independent Public Accountants    **

 *  Incorporated herein by reference as indicated.
**  Filed herewith.
 +  Management contract, compensatory plan or arrangement required
    to be filed as an exhibit to this form pursuant to Item 14(c)
    of this report.

(b) Reports on Form 8-K

    Form 8-K was filed on January 3, 2002.  Under Item 5 -- Other
    Events, the company reported the sale of 189,689 shares of
    company Common Stock to Ensign Peak Advisors, Inc. and 379,376
    shares of company Common Stock to Carlson Capital, L.P.

    Form 8-K was filed on January 25, 2002.  Under Item 5 --
    Other Events, the company reported the press release issued
    January 24, 2002, regarding earnings for 2001.

    Form 8-K was filed on February 20, 2002.  Under Item 4 --
    Changes in Registrant's Certifying Accountant, the company
    reported the dismissal of Arthur Andersen LLP as the company's
    independent auditors following the 2001 audit.


                           SIGNATURES

    Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.

                              MDU RESOURCES GROUP, INC.

    Date:  March 1, 2002      By: /s/ Martin A. White
                                  Martin A. White (Chairman of
                                  the Board, President and Chief
                                  Executive Officer)

   Pursuant to the requirements of the Securities Exchange Act
of 1934, this report has been signed below by the following
persons on behalf of the registrant in the capacities and on the
date indicated.

            Signature                             Title              Date

    /s/ Martin A. White                      Chief Executive     March 1, 2002
 Martin A. White (Chairman of the Board,           Officer
 President and Chief Executive Officer)         and Director

    /s/ Douglas C. Kane                            Chief         March 1, 2002
Douglas C. Kane (Executive Vice President,    Administrative &
Chief Administrative & Corporate                 Corporate
       Development Officer)                 Development Officer
                                                and Director

    /s/ Warren L. Robinson                    Chief Financial    March 1, 2002
Warren L. Robinson (Executive Vice President,      Officer
Treasurer and Chief Financial Officer)

    /s/ Vernon A. Raile                      Chief Accounting    March 1, 2002
 Vernon A. Raile (Vice President,                  Officer
Controller and Chief Accounting Officer)


    /s/ Harry J. Pearce                        Lead Director     March 1, 2002
        Harry J. Pearce


    /s/ Bruce R. Albertson                        Director       March 1, 2002
        Bruce R. Albertson


    /s/ Thomas Everist                            Director       March 1, 2002
        Thomas Everist


    /s/ Dennis W. Johnson                         Director       March 1, 2002
        Dennis W. Johnson


    /s/ Robert L. Nance                           Director       March 1, 2002
        Robert L. Nance


    /s/ John L. Olson                             Director       March 1, 2002
        John L. Olson


    /s/ Homer A. Scott, Jr.                       Director       March 1, 2002
        Homer A. Scott, Jr.


    /s/ Joseph T. Simmons                         Director       March 1, 2002
        Joseph T. Simmons


    /s/ Sister Thomas Welder                      Director       March 1, 2002
        Sister Thomas Welder


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.A
<SEQUENCE>3
<FILENAME>exeinc10a.txt
<DESCRIPTION>EXECUTIVE INCENTIVE COMPENSATION PLAN
<TEXT>

                   MDU RESOURCES GROUP, INC.

             EXECUTIVE INCENTIVE COMPENSATION PLAN
   ____________________________________________________________


I.   PURPOSE
     The purpose of the Executive Incentive Compensation Plan
(the "Plan") is to provide an incentive for key executives of MDU
Resources Group, Inc. (the "Company") to focus their efforts on
the achievement of challenging and demanding corporate
objectives.  The Plan is designed to reward successful corporate
performance as measured against specified performance goals as
well as exceptional individual performance.  When corporate
performance reaches or exceeds the performance targets and
individual performance is exemplary, incentive compensation
awards, in conjunction with salaries, will provide a level of
compensation which recognizes the skills and efforts of the key
executives.

II.  BASIC PLAN CONCEPT
     The Plan provides an opportunity to earn annual incentive
compensation based on the achievement of specified annual
performance objectives.  A target incentive award for each
individual within the Plan is established based on the position
level and actual base salary, provided, however, that the
Committee in its sole discretion, may, instead of actual base
salary, use the assigned salary grade market value (midpoint)
("Salary").  The target incentive award represents the amount to
be paid, subject to the achievement of the performance objective
targets established each year.  Larger incentive awards than
target may be authorized when performance exceeds targets; lesser
or no amounts may be paid when performance is below target.
     It is recognized that during a Plan Year major unforeseen
changes in economic and environmental conditions or other
significant factors beyond the control of management may
substantially affect the ability of the Plan Participants to
achieve the specified performance goals.  Therefore, in its
review of corporate performance the Compensation Committee of the
Board of Directors (the "Committee"), in consultation with the
Chief Executive Officer of MDU Resources Group, Inc., may modify
the performance targets.  However, it is contemplated that such
target modifications will be necessary only in years of unusually
adverse or favorable external conditions.

III. ADMINISTRATION
     The Plan shall be administered by the Committee with the
assistance of the Chief Executive Officer of the MDU Resources
Group, Inc.  The Committee shall approve annually, prior to the
beginning of each Plan Year, the list of eligible Participants,
the Plan's performance targets, and the target incentive award
level for each position within the Plan.  The Committee shall
have final discretion to determine actual award payment levels,
method of payment, and whether or not payments shall be made for
any Plan Year.

IV.  ELIGIBILITY
     Executives who are determined by the Committee to have a key
role in both the establishment and achievement of Company
objectives shall be eligible to participate in the Plan.

V.   PLAN PERFORMANCE MEASURES
     Performance measures shall be established that consider
shareholder and customer interests.  These measures shall be
evaluated annually based on achievement of specified goals.
     The performance measure reflective of shareholder's
interest will be the percentage attainment of corporate goals,
as determined each year by the Committee.  This measure may be
applied at the corporate level for individuals, such as the
Chief Executive Officer, or at the business unit level for
individuals whose major or sole impact is on business unit
results.
     Individual performance will be assessed based on the
achievement of annually established individual objectives.
     Threshold, target and maximum award levels will be
established annually for each performance measure and business
unit.  The Committee will retain the right to make all
interpretations as to the actual attainment of the desired
results and will determine whether any circumstances beyond the
control of management need to be considered.

VI.  TARGET INCENTIVE AWARDS
     Target incentive awards will be expressed as a percentage of
each Participant's Salary.  These percentages shall vary by
position and reflect larger reward opportunity for positions
having greater effect on the establishment and accomplishment of
the Company's or business unit's objectives.  An exhibit showing
the target awards as a percentage of Salary for eligible
positions will be attached to this Plan at the beginning of each
Plan Year.

VII. INCENTIVE FUND DETERMINATION
     The target incentive fund is the sum of the individual
target incentive awards for all eligible Participants.  The
actual incentive fund may be lower, equal to, or greater than the
target fund as determined by the Committee, based on actual
performance as compared with approved performance objectives.
     At the close of each Plan Year, the Chief Executive
Officer of MDU Resources Group, Inc. will prepare an analysis
showing the Company's and business unit's performance in relation
to each of the performance measures employed.  This will be
provided to the Committee for review and comparison to threshold,
target and maximum performance levels.  In addition, any
recommendations of the Chief Executive Officer will be presented
at this time.  The Committee will then determine the amount of
the target incentive fund earned.

VIII.INDIVIDUAL AWARD DETERMINATION
     Each individual Participant's award will be based first upon
the level of performance achieved by the Company or business unit
and secondly based upon the individual's performance.  The
performance measures applicable for assessing individual
performance will be established at the beginning of each Plan
Year.  The assessment by the Committee, after consultation with
the Chief Executive Officer, of achievement relative to the
established performance measures, as determined by a percentage
from 0 percent to 200 percent, will be applied to the
Participant's target incentive award which has been first
adjusted for Company or business unit performance.

IX.  PAYMENT OF AWARDS
     Except as provided below or as otherwise determined by the
Committee, in order to achieve an award under the Plan, the
Participant must remain in the employment of the Company or
business unit for the entire Plan Year and be an employee on the
Payment Date.  If a Participant terminates employment with MDU
Resources Group, Inc. pursuant to Section 5.01 of the Company's
Bylaws which provides for mandatory retirement for certain
officers on their 65th birthday (or terminates employment with a
subsidiary of the Company pursuant to a similar subsidiary Bylaw
provision) and if the Participant's 65th birthday occurs during
the Plan Year, determination of whether the performance measures
have been met will be made at the end of the Plan Year, and to
the extent met, payment of the award will be made to the
Participant, prorated.  Proration of awards shall be based upon
the number of full months elapsed from and including January to
and including the month in which the Participant's 65th birthday
occurs.
     An individual Participant who transfers between the Company
and business units may receive a prorated award at the discretion
of the Committee.  If employment is terminated prior to the
Payment Date as a result of death, disability or retirement, or
due to special circumstances as determined by the Committee,
payment may be made after termination.  Payments made under this
Plan will not be considered part of compensation for pension
purposes.  Payments when made will be in cash.  Incentive awards
may be deferred if the appropriate elections have been executed
prior to the end of the Plan Year.  Deferred amounts will accrue
interest at a rate determined annually by the Committee.
     In the event of a "Change in Control" (as defined by the
Committee in its Rules and Regulations) then any award deferred
by each Participant shall become immediately payable to the
Participant in cash, together with accrued interest thereon to
the date of payment.  In the event the Participant files suit to
collect the Participant's deferred award then all of the court
costs, other expenses of litigation, and attorneys' fees shall be
paid by the Company in the event the Participant prevails upon
any of the Participant's claims for payment of a deferred award.



                    MDU RESOURCES GROUP, INC.

              EXECUTIVE INCENTIVE COMPENSATION PLAN

                      RULES AND REGULATIONS

     The Compensation Committee of the Board of Directors of MDU
Resources Group, Inc. (the "Company") adopted Rules and
Regulations for the administration of the Management Incentive
Compensation Plan (the "Plan") on February 9, 1983, following
adoption of the Plan by the Board of Directors of the Company on
November 4, l982.

I.   DEFINITIONS
     The following definitions shall be used for purposes of
these Rules and Regulations and for the purposes of administering
the Plan:

     1.   The "Committee" shall be the
          Compensation Committee of the Board of
          Directors of the Company.

     2.   The "Company" shall refer to MDU
          Resources Group, Inc. alone and shall not
          refer to its utility division or to any of
          its subsidiary corporations.

     3.   "Participants" for any Plan Year shall
          be those executives who have been approved by
          the Committee as eligible for participation
          in the Plan for such Plan Year.

     4.   "Payment Date" shall be the date set by
          the Committee for payment of awards, other
          than those awards deferred pursuant to
          Section IX of the Plan and Section VII of
          these Rules and Regulations.

     5.   The "Plan" shall refer to the Executive
          Incentive Compensation Plan.

     6.   The "Plan Year" shall be the calendar year.

     7.   "Change in Control" shall mean the
          earlier of the following to occur:  (a) the
          public announcement by the Company or by any
          person (which shall not include the Company,
          any subsidiary of the Company or any employee
          benefit plan of the Company or of any
          subsidiary of the Company) ("Person") that
          such Person, who or which, together with all
          Affiliates and Associates (within the
          meanings ascribed to such terms in Rule 12b-2
          of the General Rules and Regulations under
          the Securities Exchange Act of 1934, as
          amended (17 C.F.R. 240.12b-2)) of such
          Person, shall be the beneficial owner of
          twenty percent (20%) or more of the voting
          stock then outstanding; (b) the commencement
          of, or after the first public announcement of
          any Person to commence, a tender or exchange
          offer the consummation of which would result
          in any Person becoming the beneficial owner
          of voting stock aggregating thirty percent
          (30%) or more of the then outstanding voting
          stock; (c) the announcement of any
          transaction relating to the Company required
          to be described pursuant to the requirements
          of Item 6(e) of Schedule 14A of Regulation
          14A of the Securities and Exchange Commission
          under the Securities Exchange Act of 1934 (17
          C.F.R. 240.14a-101, item 6(e)); (d) a
          proposed change in the constituency of the
          Board of Directors of the Company such that,
          during any period of two (2) consecutive
          years, individuals who at the beginning of
          such period constitute the Board of Directors
          of the Company cease for any reason to
          constitute at least a majority thereof,
          unless the election or nomination for
          election by the shareholders of the Company
          of each new Director was approved by a vote
          of at least two-thirds (2/3) of the directors
          then still in office who were members of the
          Board of Directors of the Company at the
          beginning of the period; or (e) any other
          event which shall be deemed by a majority of
          the Compensation Committee of the Board of
          Directors of the Company to constitute a
          "Change in Control."

     8.   The "Prime Rate" shall be the base rate
          on corporate loans posted by at least 75
          percent of the nation's 30 largest banks as
          reported daily in The Wall Street Journal.

II.  ADMINISTRATION

     1.   The Committee shall have the full power
          to construe and interpret the Plan and to
          establish and to amend these Rules and
          Regulations for its administration.

     2.   No member of the Committee shall
          participate in a decision as to their own
          eligibility for, or award of, an incentive
          award payment.

     3.   Prior to the beginning of each Plan
          Year, the Committee shall approve a list of
          eligible executives and notify those so
          approved that they are eligible to
          participate in the Plan for such Plan Year.

     4.   Prior to the beginning of each Plan
          Year, the Committee shall draw up an Annual
          Operating Plan.  The Annual Operating Plan
          shall include the Plan's performance measures
          and performance targets as well as the target
          incentive award levels for each salary grade
          covered by the Plan for the following Plan
          Year.  The Annual Operating Plan, insofar as
          it is relevant to each individual
          Participant, shall be made available by the
          Committee to each Participant in the Plan at
          the beginning of each Plan Year.

     5.   The Committee shall have final
          discretion to determine actual award payment
          levels, method of payment, and whether or not
          payments shall be made for any Plan Year.
          However, unless the Plan's performance
          objectives are met for the Plan Year, no
          award shall be made for that Plan Year.
          Performance targets modified pursuant to
          Section II of the Plan will be deemed
          performance targets for purposes of
          determining whether or not these targets have
          been met.

III. PLAN PERFORMANCE MEASURES

     1.   The Committee shall establish the
          percentage attainment of corporate
          performance measure and the percentage
          attainment of individual goals measure.  The
          Committee may establish more or fewer
          performance measures as it deems necessary.

     2.   The corporate performance measure may
          be set by reference to earnings, return on
          invested capital or any other measure or
          combination of measures deemed appropriate
          by the Committee.  It may be established for
          the Company or for the individual business
          unit.

     3.   Individual performance will be assessed
          based on the achievement of annually
          established individual objectives.

     4.   Plan performance measures may be
          applied at the corporate level for
          individuals such as the Chief Executive
          Officer whose major or sole impact is
          Company-wide, or at the business unit level
          for individuals whose major or sole impact
          is on the business unit results.  The Annual
          Operating Plan shall contain a list of
          individuals to whom the Plan performance
          measures will be applied at the corporate
          level and a list of those individuals for
          whom the Plan performance measures will be
          applied at the business unit level.  The
          relevant business unit for each individual
          will be identified.

     5.   The Committee shall set threshold,
          target and maximum award levels for the
          performance measures, for each business
          unit, and for the Company.  Those levels
          shall be included in the Annual Operating
          Plan.

     6.   The Committee will retain the authority
          to determine whether or not the actual
          attainment of these measures has been made.

IV.  TARGET INCENTIVE AWARDS

     1.   Target incentive awards will be a
          percentage of each Participant's Salary, as
          defined in the Plan.

     2.   Target incentive awards shall be set by
          the Committee annually and will be included
          in the Annual Operating Plan.

 V.  INCENTIVE FUND DETERMINATION

     1.   The target incentive fund is the sum of
          the individual target incentive awards for
          all eligible Participants.

     2.   The actual incentive fund will be
          determined by the Committee, based on actual
          performance as compared with the approved
          performance measures.

     3.   As soon as practicable following the
          close of each Plan Year, the Chief Executive
          Officer will provide the Committee with an
          analysis showing the Company's and each
          relevant business unit's performance in
          relation to both of the performance measures.
          The Committee will review the analysis and
          determine, in its sole discretion, the amount
          of the actual incentive fund.

     4.   In determining the actual incentive
          fund, the Committee may consider any
          recommendations of the Chief Executive
          Officer.

VI.  INDIVIDUAL AWARD DETERMINATION

     1.   The Committee shall have the sole
          discretion to determine each individual
          Participant's award. The Committee's decision
          will be based first upon the level of
          performance achieved by the
          Company or business unit and second upon the
          individual's performance.

     2.   The Committee, after consultation with
          the Chief Executive Officer, shall set the
          award as a percentage from 0 percent to 200
          percent of the Participant's target incentive
          award, adjusted for Company or business unit
          performance.

VII. PAYMENT OF AWARDS

     1.   On the date the Committee determines the
          awards to be made to individual Participants,
          it shall also establish the Payment Date.

     2.   Except as provided below or as the
          Committee otherwise determines, in order to
          receive an award under the Plan, a
          Participant must remain in the employment of
          the Company for the entire Plan Year and be
          an employee on the Payment Date.

     3.   If employment is terminated prior to
          Payment Date as a result of death, disability
          or retirement, or due to special
          circumstances as determined by the Committee
          in its sole discretion, payment may be made
          after termination.

     4.   If a Participant terminates employment
          with the Company pursuant to Section 5.01 of
          the Company's Bylaws which provides for
          mandatory retirement for certain officers on
          their 65th birthday (or terminates employment
          with a subsidiary of the Company pursuant to
          a similar subsidiary Bylaw provision) and if
          the Participant's 65th birthday occurs during
          the Plan Year, determination of whether the
          performance measures have been met will be
          made at the end of the Plan Year, and to the
          extent met, payment of the award will be made
          to the Participant, prorated.  Proration of
          awards shall be based upon the number of full
          months elapsed from and including January to
          and including the month in which the
          Participant's 65th birthday occurs.

     5.   Payment of the awards shall be made in
          cash.  Payments shall be made on the Payment
          Date unless the Participant has deferred, in
          whole or in part, the receipt of the award by
          making an election on the deferral form
          attached hereto, prior to the end of the Plan
          Year immediately preceding the Payment Date.

     6.   In the event a Participant has elected
          to defer receipt of all or a portion of the
          award, the Company shall set up an account in
          their name. The amount of their award to the
          extent deferred will be credited to the
          Participant's account on the Payment Date.

     7.   The balance credited to an account of a
          Participant who has elected to defer receipt
          of an award will be an unsecured, unfunded
          obligation of the Company.

     8.   Interest shall accrue on the balance
          credited to a Participant's account.  The
          rate of interest shall be the Prime Rate plus
          1 percentage point as reported on the last
          Friday in January of each year.  Interest on
          the balance in an account shall accrue at the
          rate so determined from the Payment Date
          immediately following the determination to
          the Payment Date of the following year.

     9.   Interest shall be credited to the
          account on the day preceding Payment Date and
          shall be calculated on the balance in the
          Participant's account as of that date.

    10.   A Participant may elect to defer any
          percentage, not to exceed l00, of an annual
          award.

    11.   A Participant electing to defer any part of
          an award must elect one of the following
          dates for payment:

          (1)  Retirement date;

          (2)  Payment Date next
               following termination of
               employment; or

          (3)  Payment Date of the fifth
               year following the year in which
               the award may be made.

    12.   A Participant may elect to receive the
          deferred amounts accumulated in the
          Participant's account in monthly
          installments, not to exceed 120.  In the
          event the Participant elects to receive the
          amounts in the Participant's account in more
          than one installment, interest shall continue
          to accrue on the balance remaining in their
          account at the applicable rate or rates
          determined annually by the Committee.

    13.   In the event of the death of a Participant in
          whose name a deferred account has been set
          up, the Company shall, within six months
          thereafter, pay to the Participant's estate
          or the designated beneficiary the entire
          amount in the deferred account.

    14.   In the event of a "Change in Control" then
          any award deferred by each Participant shall
          become immediately payable to the
          Participant.  In the event the Participant
          files suit to collect a deferred award then
          all of the Participant's court costs, other
          expenses of litigation, and attorneys' fees
          shall be paid by the Company in the event the
          Participant prevails upon any of the
          Participant's claims for payment.




</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.D
<SEQUENCE>4
<FILENAME>dircomp10d.txt
<DESCRIPTION>DIRECTORS' COMPENSATION POLICY
<TEXT>

                   MDU RESOURCES GROUP, INC.

                 DIRECTORS' COMPENSATION POLICY


     Each Director who is not a full-time employee of the Company
shall receive compensation made up of annual cash retainers,
common stock and meeting fees.  Each Director is also eligible
for awards under the 1997 Non-Employee Director Long-Term
Incentive Plan.

Annual Retainers, Stock Compensation and Stock Option Grants

     The Board service annual cash retainer shall be $20,000.
The annual retainer for service as Chairman of the Audit,
Compensation, Finance and Nominating Committees shall be $4,000.
Such retainers shall be paid in monthly installments.

     The Amended and Restated Deferred Compensation Plan for
Directors adopted on February 13, 1992 and effective January 1,
1992, as amended, permits a Director to defer all or any portion
of the annual cash retainer, as well as meeting fees and any
other cash compensation paid for service as a Director.  The
amount deferred is recorded in each participant's deferred
compensation account and credited with income in the manner
prescribed in the Plan.  For further details, reference is made
to the Plan, a copy of which is attached.

     Each Director shall receive 1,000 shares of Common Stock on
or about the 15th business day following the annual meeting of
stockholders, pursuant to the Non-Employee Directors Stock
Compensation Plan, effective April 25, 1995, as amended.  A
Director may decline a stock payment for any plan year, in
writing in advance of the plan year to which stock payment
relates.  No cash compensation shall be paid in lieu thereof.  By
written election a Director may reduce the cash portion of the
annual retainer and have that amount applied to the purchase of
additional shares.  The election must be made on a form provided
by the administrative committee and returned to the committee by
the last business day of the year prior to the year in which the
election is to be effective.  The election remains in effect
until changed or revoked.  No election may be changed or revoked
for the current year, but may be changed for a subsequent year.
For further details, reference is made to the Non-Employee
Director Stock Compensation Plan, a copy of which is attached.

     Each Director shall receive an option grant annually to
purchase 3,000 shares of Company Common Stock.  The option shall
vest immediately and is exercisable for 10 years from the date of
the grant.  The option price is the fair market value of the
stock at the time of the grant.  The option grant is made
pursuant to the 1997 Non-Employee Director Long-Term Incentive
Plan.

Board and Committee Meeting Fee

     The fee for each Board meeting attended shall be $1,500 and
for each meeting attended of each Committee of which the Director
is a member, and for attendance at Planning and Pension meetings,
shall be $1,000, payable only to Directors who are not full-time
employees of the Company.

Travel Expense Reimbursement

     All Directors will be reimbursed for reasonable travel
expenses including spouse's expenses (providing the spouse
participates in ALL business, community, spouse-specific and
social events), in connection with attendance at meetings of the
Company's Board of Directors and its committees.  If the travel
expense is related to the reimbursement of commercial airfare,
such reimbursement will not exceed full-coach rate.  If the
travel expense is related to reimbursement of non-commercial
airfare, such reimbursement will not exceed the rate for
comparable travel by means of commercial airline at the first-
class rate.

Directors' Liability

     Article Seventeenth of the Company's Restated Certificate of
Incorporation provides that no Director of the Company shall be
liable to the Company or its stockholders for breach of fiduciary
duty as a Director, with certain exceptions stated below.
Section 7.07 of the Company's Bylaws requires the Company to
indemnify fully a Director against expenses, attorneys fees,
judgments, fines and amounts paid in settlement of any suit,
action or proceeding, whether civil or criminal, arising from an
action of a Director by reason of the fact that the Director was
a Director of MDU Resources Group, Inc.

     There are exceptions to these protections:  breaches of the
Directors' duty of loyalty to the Company or its stockholders,
acts or omissions not in good faith or which involve intentional
misconduct or a knowing violation of the law, violation of
Section 174 of the Delaware General Corporation Law (relating to
unlawful declaration of dividends and unlawful purchase of the
company's stock), and transactions from which the Director
derived an improper personal benefit (including short-swing
profits under Section 16(b) of the Securities Exchange Act of
1934).

     The Company has and does maintain Directors' and Officers'
liability insurance coverage with a $100,000,000 limit.

Insurance Coverages

     The Company maintains the following insurance for protection
of its Directors as they carry out the business of MDU Resources
Group, Inc.

     1.   General liability and automobile
          liability insurance:

          The Directors are afforded coverage
          under the general liability and automobile
          liability insurance of the Company. The
          policy limit is $75,000,000 in excess of self-
          insured retentions of $500,000 per
          occurrence for general liability and $250,000
          per occurrence for automobile liability; or
          $1,000,000 per occurrence/$2,000,000
          aggregate for general liability and
          $1,000,000 per occurrence for automobile
          liability, where we are carrying primary
          layer insurance coverage.

     2.   Fiduciary and employee benefit liability insurance:

          The Directors are afforded coverage
          under the fiduciary and employee benefits
          liability insurance of the Company.  The
          policy has a $35,000,000 limit with no
          deductible applicable to the Director.

     3.   Aircraft liability insurance:

          The Company's existing aircraft
          liability insurance policy extends coverage
          while a non-owned* aircraft is used by a
          Director in traveling to and from Director or
          Board committee meetings.  This insurance
          coverage constitutes excess liability
          coverage in the amount of $200,000,000.

          *Non-owned aircraft is defined as:  1)
          any aircraft registered under a "standard"
          airworthiness certificate issued by the FAA;
          2) aircraft with a seating capacity not
          exceeding 40 seats; 3) aircraft that are not
          owned by MDU Resources Group, Inc. or any of
          its subsidiaries; 4) aircraft that are not
          partly or wholly owned by or registered in
          the Director's name or the name of any
          Director's household member.

     4.   Travel and sojourn insurance:

          All Directors are protected by a group
          insurance policy with coverage of $250,000
          that provides 24-hour accident protection
          while traveling on Company business.

          Coverage in all instances begins at the
          actual start of a business trip and ends when
          the Director returns to his/her home or
          regular place of employment.

          The beneficiary of the insurance will be
          that beneficiary recorded on a beneficiary
          designation card provided by the Company.

     5.   Group life insurance:

          All outside Directors are protected by a
          non-contributory group life insurance policy
          with coverage of $100,000.

          The coverage begins the day the Director
          is elected to the Board of Directors and
          terminates when the Director ceases to be an
          outside Director.

          A Certificate of Insurance shall be
          provided to the Director and the beneficiary
          of the insurance will be that beneficiary
          recorded on a beneficiary designation card
          provided by the Company.

          This protection is considered taxable
          compensation under current tax laws.
          Consequently, the Company will provide each
          Director annually on Form 1099 the amount of
          taxable income related to this coverage.




</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.E
<SEQUENCE>5
<FILENAME>defcomplan10e.txt
<DESCRIPTION>DEFERRED COMPENSATION PLAN FOR DIRECTORS
<TEXT>

                    MDU RESOURCES GROUP, INC

                      Amended and Restated
            DEFERRED COMPENSATION PLAN FOR DIRECTORS
                    Effective January 1, 1992


  I. PURPOSE

     The Board of Directors of MDU Resources Group, Inc. (the
"Company") established the Deferred Compensation Plan for
Directors (the "Plan") effective as of September l, 1988.  The
Plan is hereby amended and restated effective January 1, 1992,
and is substituted for the Restated Plan established by the
Company on August 1, 1991.  The Plan shall continue until
terminated by the Board of Directors of the Company, subject to
the provisions of Article XII, below.

     The purpose of this Plan is to aid the Company in attracting
and retaining as Directors persons whose abilities, experience
and judgment can contribute to the continued progress of the
Company.  The Plan will provide a method of deferring
compensation to the Directors.


 II. DEFINITIONS

     A.   Beneficiary.  "Beneficiary" means the person or
          persons designated as such in accordance with Article
          XI.

     B.   Change in Control.  "Change in Control" means the
          earliest of the following to occur: (a) the public
          announcement by the Company or by any person (which
          shall not include the Company, any subsidiary of the
          Company, or any employee benefit plan of the Company or
          of any subsidiary of the Company) ("Person") that such
          Person, who or which, together with all Affiliates and
          Associates (within the meanings ascribed to such terms
          in the Rule 12b-2 of the General Rules and Regulations
          under the Exchange Act) of such Person, shall be the
          beneficial owner of twenty percent (20%) or more of the
          voting stock of the Company outstanding; (b) the
          commencement of, or after the first public announcement
          of any Person to commence, a tender or exchange offer
          the consummation of which would result in any Person
          becoming the beneficial owner of voting stock
          aggregating thirty percent (30%) or more of the then
          outstanding voting stock of the Company; (c) the
          announcement of any transaction relating to the Company
          required to be described pursuant to the requirements
          of Item 6(e) of Schedule 14A of Regulation 14A under
          the Exchange Act; (d) a proposed change in constituency
          of the Board of Directors such that, during any period
          of two (2) consecutive years, individuals who at the
          beginning of such period constitute the Board of
          Directors cease for any reason to constitute at least a
          majority thereof, unless the election or nomination for
          election by the stockholders of the Company of each new
          Director was approved by a vote of least two-thirds
          (2/3) of the Directors then still in office who were
          members of the Board of Directors at the beginning of
          the period; or (e) any other event which shall be
          deemed by a majority of the Board of Directors to
          constitute a "Change in Control."

     C.   Compensation and Deferral Amount. "Compensation"
          means any cash retainer, meeting fees and any other
          cash compensation payable to Eligible Directors by the
          Company for services as a Director.  This Deferred
          Compensation Plan for Directors governs any or all of
          that Compensation which the Participant elects to
          credit to his Deferred Compensation Account, which is
          hereafter referred to as the "Deferral Amount."

     D.   Deferred Compensation Account.  "Deferred
          Compensation Account" means the account maintained on
          the books of account of the Company for each
          Participant pursuant to Article VI.

     E.   Effective Date.  "Effective Date" means January 1,
          1992, the date on which the restated and amended Plan
          became effective.

     F.   Eligible Director.  "Eligible Director" means
          those Directors of the Company who are not employees of
          the Company.

     G.   Investment Units.  This term shall have the
          meaning defined in Article VI.B.

     H.   Market Price.  "Market Price" means the average of
          the highest and lowest transaction prices for the
          Company's common stock on the New York Stock Exchange
          for a given day.

     I.   Participant.  "Participant" means an Eligible
          Director participating in the Plan in accordance with
          the provisions of Article IV.

     J.   Plan Year.  "Plan Year" means the calendar year.


III. ADMINISTRATION OF THE PLAN

     The Board of Directors shall be the sole administrator of
the Plan.

     The Board of Directors may from time to time establish
rules and regulations for the administration of the Plan.

     All determinations of the Board of Directors, irrespective
of their character or nature, including, but not limited to, all
questions of construction and interpretation, shall be final,
binding and conclusive upon all parties.  Without limiting the
generality of the foregoing, the determination of the Board of
Directors as to whether a Participant has terminated his services
and the date thereof shall be final, binding and conclusive upon
all persons.

     The Company and/or the Board of Directors may consult with
legal counsel, who may be counsel for the Company or other
counsel, with respect to its obligations and duties hereunder or
with respect to any claim, action or proceeding or any other
matter, and shall not be liable for any action taken or not taken
by it in good faith pursuant to the advice of such counsel.

     The Chairman, at the direction of the Board of Directors
shall be responsible for maintaining books and records for the
Plan and adopting standard forms for such matters as beneficiary
designations and applications for benefits, provided such rules
and forms are not inconsistent with the provisions of the Plan.
Such books and records shall only be open for examination by a
Participant or his duly designated beneficiary to the extent that
they specifically involve the Deferred Compensation Account
created for his benefit or any payments which are to be made to
him or his beneficiary hereunder.  Each Participant or his duly
designated beneficiary shall be notified no less frequently than
annually of the balance in his account.

     Neither the Board of Directors nor any member of the Board
of Directors nor the Company nor any other person who is acting
on behalf of the Board of Directors or the Company shall be
liable for any act or failure to act hereunder except for gross
negligence or fraud.


 IV. PARTICIPATION

     All Eligible Directors, including any person who becomes a
Director after the effective date hereof, shall be Participants
in the Plan.

     Each Participant in the Plan shall have the right to elect
to defer the payment of all or any part of his Compensation, with
such Deferral Amount to be payable at the time or times and in
the manner hereinafter stated.

     Each Participant who elects to defer the payment of all or
any part of his Compensation shall execute and deliver to the
Board of Directors a "Notice of Election."  Such Notice will
provide the percentage of his Compensation to be deferred, the
date such deferral is to commence and the beneficiary
designations of the Director.  Such deferral election shall be
applicable only to Compensation earned by reason of services
rendered after the date of such Notice.

     An election to defer Compensation shall continue in effect
until revoked or modified by a subsequent "Notice of Election,"
provided however, (1) that every election to defer shall be
irrevocable as to Compensation earned prior to the date of
revocation and (2) that such election may be changed no more
often than annually.  Revocation or modification shall be made in
writing to the Board of Directors and shall be effective upon the
date stated therein.


  V. VESTING OF DEFERRED COMPENSATION ACCOUNT

     A Participant's interest in his Deferred Compensation
Account shall vest immediately with regard to Deferral Amounts
and earnings thereon.


 VI. ACCOUNTS AND VALUATIONS

     A.   Deferred Compensation Accounts.  The Board of
          Directors shall establish and maintain a separate
          Deferred Compensation Account for each Participant.  The
          Participant's Deferral Amount shall be credited to the
          Participant's Deferred Compensation Account quarterly
          on the first day of March, June, September and December
          in amounts as nearly equal as possible.

     B.   Conversion to Investment Units.  At the time a
          Deferral Amount is credited to the Deferred
          Compensation Account, it shall be converted to
          Investment Units, by dividing the amount deferred by
          the Market Price of the Company's stock on the first
          trading day immediately preceding the deferral.
          Fractional share Investment Units will be maintained in
          the Account.


VII. DIVIDEND EQUIVALENTS

     If a dividend is declared on the common stock of the
Company, an equivalent amount shall be credited to the
Participant's Deferred Compensation Account for each Investment
Unit.  Such amounts shall be converted to additional Investment
Units, pursuant to Article VI.B.


VIII.DISTRIBUTION

     A.   Conversion of Investment Units to Dollars.  When a
          Participant leaves the Board of Directors, dies, or
          becomes disabled, Investment Units in the Participant's
          Deferred Compensation Account shall be converted into
          dollars, on the dates set forth below, based on the
          Market Price of the Company's common stock on the date
          of conversion.  If the New York Stock Exchange is not
          open that day, then it shall be the Market Price on the
          next day the New York Stock Exchange is open.  During
          the period before conversion, if a dividend is declared
          on common stock of the Company, an equivalent amount
          shall be credited to the Participant's Deferred
          Compensation Account for each Investment Unit then
          remaining credited and not converted.  Such amounts
          shall be converted into additional Investment Units.

     B.   Payment.  On the day that is six full calendar
          months after the Participant's date of leaving the
          Board, death or disability, 20 percent of the value of
          the Investment Units credited to the Participant's
          Deferred Compensation Account shall be converted to
          dollars and paid to the Participant in substantially
          equal monthly payments over a one-year period (the
          "First Year Payout").  On the day that is one year
          after the date of the first conversion, 25 percent of
          the remaining value of the Investment Units shall be
          converted to dollars and paid to the Participant in
          substantially equal monthly payments over a one-year
          period (the "Second Year Payout").  The following year,
          33 1/3 percent of the remaining value shall be
          converted and paid out as above (the "Third Year
          Payout"), the fourth year, 50 percent of the remaining
          value shall be paid out as the "Fourth Year Payout",
          and the fifth year, the remaining balance shall be paid
          out as the "Fifth Year Payout."  As indicated above,
          "dividends" shall be credited on Investment Units
          before they are converted, which shall be converted
          into additional Investment Units.  No interest will be
          paid on amounts in the Deferred Compensation Account.

     C.   Change in Control.  The terms of this Article
          VIII.C shall immediately become operative, without
          further action or consent by any person or entity, upon
          a Change in Control, and once operative shall supersede
          and take control over any other provisions of the Plan.

          Upon a Change in Control, all Investment Units in
          a Participant's Deferred Compensation Account shall be
          multiplied by the Market Price of the Company's common
          stock on such day.  If the New York Stock Exchange is
          not open on that day, then it shall be the Market Price
          on the next day the New York Stock Exchange is open.
          The dollar value of the Investment Units contained in
          each Participant's Deferred Compensation Account shall
          be paid out immediately thereafter to the Participant
          (a "Change in Control Payment".)

          In addition, the Company shall pay to the
          Participant an additional payment (a "Gross-Up
          Payment") in an amount such that after payment by the
          Participant of all federal and state income taxes
          (including, without limitation, any and all federal and
          state income taxes imposed upon the Gross-Up Payment)
          the Participant retains an amount of the Gross-Up
          Payment equal to the federal and state income taxes
          imposed upon the Change in Control Payment.

          All determinations required to be made under this
          Article VIII.C, including when a Gross-Up Payment is
          required, the amount of such Gross-Up Payment, and the
          assumptions to be utilized in arriving at such
          determination, shall be made by a certified public
          accounting firm designated by the Participant (the
          "Accounting Firm"), which shall provide detailed
          supporting calculations both to the Company and the
          Participant within 15 business days of the receipt of
          notice from the Participant that there has been a
          Change in Control Payment (or such earlier time as is
          requested by the Company).  All fees and expenses of
          the Accounting Firm related to the calculations
          required by this Article VIII.C shall be borne solely
          by the Company.  Any Gross-Up Payment, as determined
          pursuant to this Article VIII.C, shall be paid by the
          Company to the Participant within five days of the
          receipt of the Accounting Firm's determination.  Any
          determination by the Accounting Firm shall be binding
          upon the Company and the Participant.

 IX. TAX WITHHOLDING UPON DISTRIBUTION

     To the extent required by law, the Company shall withhold
from payments made hereunder any taxes required to be withheld by
the federal or any state or local government.


  X. COMMENCEMENT OF PAYMENTS

     Except as otherwise provided in this Plan, commencement of
payments under this Plan shall begin as soon as administratively
feasible after the value of the Investment Units is determined
according to Article VIII.

 XI. BENEFICIARY DESIGNATION

     Each Participant shall have the right at any time to
designate any person or persons as Beneficiary or Beneficiaries
(both principal and contingent) to whom payment under this Plan
shall be paid in the event of death prior to complete
distribution of the deferred amounts under the Plan.  Each
beneficiary designation shall become effective only when filed in
writing with the Board of Directors during the Participant's
lifetime on a form provided by the Board of Directors.

     The filing of a new beneficiary designation form will cancel
all beneficiary designations previously filed.  Any finalized
divorce of a Participant subsequent to the date of filing of a
beneficiary designation form shall revoke such designation.  The
spouse of a married Participant domiciled in a community property
jurisdiction shall join in any designation of Beneficiary or
Beneficiaries other than the spouse.

     If a Participant fails to designate a Beneficiary as
provided above or if the beneficiary designation is revoked by
divorce, or otherwise, without execution of a new designation, or
if all designated Beneficiaries predecease the Participant or die
prior to complete distribution of the Participant's benefits,
then the distribution of such benefits shall be made to the
Participant's estate.

     If any distribution to a Beneficiary is to be made in
installments, and the primary Beneficiary dies before receiving
all installments, the remaining installments, if any, shall be
paid to the estate of the primary Beneficiary in a lump sum.


XII. AMENDMENT AND TERMINATION OF PLAN

     A.   Amendment.  The Company may at any time amend the
          Plan in whole or in part, provided, however, that
          except as provided in Article XII.B., no amendment
          shall act to reduce the benefits under the Plan payable
          to any Participant with respect to any Deferral Amount
          credited to the Participant's Deferred Compensation
          Account prior to the date of the amendment.  Written
          notice of any amendments shall be given to each
          Participant.

     B.   Termination of Plan

          1.   Company's Right to Terminate.  The Board
               of Directors may at any time terminate the Plan.

          2.   Payments Upon Termination.  Upon any
               termination of the Plan under this section no
               additional Deferral Amounts will be credited to
               the Participant's Deferred Compensation Account.
               The Investment Units recorded in such Account
               shall be converted into dollars pursuant to
               Article VIII.A. and paid in a lump sum to the
               Participant or the Participant's Beneficiary.


XIII. MISCELLANEOUS

     A.   Unsecured General Creditor.  Participants and
          their beneficiaries, heirs, successors, and assigns
          shall have no legal or equitable rights, interests, or
          other claims in any property or assets of the Company,
          nor shall they be beneficiaries of, or have any rights,
          claims, or interests in any specified assets of the
          Company.  Any and all of the Company's assets shall be
          and remain general, unpledged, unrestricted assets of
          the Company.  The Company's obligation under the Plan
          shall be that of an unfunded and unsecured promise of
          Company to pay money in the future.

     B.   Obligations to the Company.  If a Participant
          becomes entitled to a distribution of benefits under
          the Plan, and if at such time the Participant has
          outstanding any debt, obligation, or other liability
          representing an amount owed to the Company, then the
          Company may offset such amounts owing it or an
          affiliate against the amount of benefits otherwise
          distributable.  Such determination shall be made by the
          Board of Directors.

          Establishment of this Plan and the participation
          by any person shall not be construed to confer any
          right on the part of such person to be nominated for
          reelection, or to be reelected, to the Board of
          Directors of the Company.

     C.   Nonassignability.  Neither a Participant nor any
          other person shall have any right to commute, sell,
          assign, transfer, pledge, anticipate, mortgage, or
          otherwise encumber, transfer, hypothecate, or convey in
          advance of actual receipt the amounts, if any, payable
          hereunder, or any part thereof, which are, and all
          rights to which are, expressly declared to be
          unassignable and nontransferable.  No part of the
          amounts payable shall, prior to actual payment, be
          subject to seizure or sequestration for the payment of
          any debts, judgments, alimony or separate maintenance
          owed by a Participant or any other person, nor be
          transferable by operation of law in the event of a
          Participant's or any other person's bankruptcy or
          insolvency.

     D.   Protective Provisions.  A Participant will
          cooperate with the Company by furnishing any and all
          information requested by the Company in order to
          facilitate the payment of any amounts hereunder.  If a
          Participant refuses to cooperate, the Company shall
          have no further obligation to the Participant under the
          Plan.

     E.   Gender, Singular and Plural.  Wherever the context
          so requires, words in the masculine include the
          feminine and words in the feminine include the
          masculine and the definition of any term in the
          singular may include the plural.

     F.   Captions.  The captions to the articles, sections,
          and paragraphs of this Plan are for convenience only
          and shall not control or affect the meaning or
          construction of any of its provisions.

     G.   Applicable Law.  This Plan shall be construed,
          administered and governed in accordance with the laws
          of the State of North Dakota.

     H.   Validity.  In the event any provision of this Plan
          is held invalid, void, or unenforceable, the same shall
          not affect, in any respect whatsoever, the validity of
          any other provision of this Plan.

     I.   Notice.  Any notice or filing required or
          permitted to be given to the Board of Directors shall
          be sufficient if in writing and hand delivered, or sent
          by registered or certified mail, to the principal
          office of the Company, directed to the attention of the
          Secretary of the Company.  Such notice shall be deemed
          given as of the date of delivery or, if delivery is
          made by mail, as of the date shown on the postmark on
          the receipt for registration or certification.



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.F
<SEQUENCE>6
<FILENAME>nonempdir10f.txt
<DESCRIPTION>NON-EMPLOYEE DIRECTOR STOCK COMPENSATION PLAN
<TEXT>

                   MDU RESOURCES GROUP, INC.
         NON-EMPLOYEE DIRECTOR STOCK COMPENSATION PLAN


I.   Purpose

     The purpose of the MDU Resources Group, Inc. Non-Employee
Director Stock Compensation Plan is to provide ownership of the
Company's stock to non-employee members of the Board of Directors
in order to improve the Company's ability to attract and retain
highly qualified individuals to serve as directors of the Company
and to strengthen the commonality of interest between directors
and stockholders.


II.  Definitions

     When used herein, the following terms shall have the
     respective meanings set forth below:

     "Agent" means a securities broker-dealer selected by the
     Company and registered under the Exchange Act.

     "Annual Retainer" means the annual retainer payable by the
     Company to Non-Employee Directors and shall include, for
     purposes of this Plan, meeting fees, cash retainers and any
     other cash compensation payable to Non-Employee Directors by
     the Company for services as a Director.

     "Annual Meeting of Stockholders" means the annual meeting of
     stockholders of the Company at which directors of the
     Company are elected.

     "Board" or "Board of Directors" means the Board of Directors
     of the Company.

     "Committee" means a committee whose members meet the
     requirements of Section IV(A) hereof, and who are appointed
     from time to time by the Board to administer the Plan.

     "Common Stock" means the common stock, $1.00 par value, of
     the Company.

     "Company" means MDU Resources Group, Inc., a Delaware
     corporation, and any successor corporation.

     "Effective Date" means the date as of which the Plan is
     approved by the stockholders of the Company.

     "Employee" means any officer or other common law employee of
     the Company or of any of its business units or divisions or
     of any Subsidiary.

     "Exchange Act" means the Securities Exchange Act of 1934, as
     amended.

     "Non-Employee Director" or "Participant" means any person
     who is elected or appointed to the Board of Directors of the
     Company and who is not an Employee.

     "Plan" means the Company's Non-Employee Director Stock
     Compensation Plan, adopted by the Board on February 9, 1995,
     and approved by the stockholders on April 25, 1995, as it
     may be amended from time to time.

     "Plan Year" means the period commencing on the Effective
     Date of the Plan and ending the next following December 31
     and, thereafter, the calendar year.

     "Stock Payment" means that portion of the Annual Retainer to
     be paid to Non-Employee Directors in shares of Common Stock
     rather than cash for services rendered as a director of the
     Company, as provided in Section V hereof, including that
     portion of the Stock Payment resulting from any election
     specified in Section VI hereof.

     "Subsidiary" means any corporation that is a "subsidiary
     corporation" of the Company, as that term is defined in
     Section 424(f) of the Internal Revenue Code of 1986, as
     amended.


III. Shares of Common Stock Subject to the Plan

     Subject to Section VII below, the maximum aggregate number
of shares of Common Stock that may be delivered under the Plan is
112,500 shares.  The Common Stock to be delivered under the Plan
will be made available from authorized but unissued shares of
Common Stock, treasury stock or shares of Common Stock purchased
on the open market.  Shares of Common Stock purchased on the open
market shall be purchased by the Agent in compliance with Rule
10b-6 and Rule 10b-18 under the Exchange Act to the extent
compliance shall be required.  Shares of Common Stock purchased
on the open market by the Agent shall be purchased and held in
such manner that such shares are not returned to the status of
treasury stock or authorized but unissued shares of Common Stock.


IV.  Administration

     A.   The Plan will be administered by a committee appointed
by the Board, consisting of two or more persons who are not
eligible to participate in the Plan.  Members of the Committee
need not be members of the Board.  The Company shall pay all
costs of administration of the Plan.

     B.   Subject to and not inconsistent with the express
provisions of the Plan, the Committee has and may exercise such
powers and authority of the Board as may be necessary or
appropriate for the Committee to carry out its functions under
the Plan.  Without limiting the generality of the foregoing, the
Committee shall have full power and authority (i) to determine
all questions of fact that may arise under the Plan, (ii) to
interpret the Plan and to make all other determinations necessary
or advisable for the administration of the Plan and (iii) to
prescribe, amend and rescind rules and regulations relating to
the Plan, including, without limitation, any rules which the
Committee determines are necessary or appropriate to ensure that
the Company and the Plan will be able to comply with all
applicable provisions of any federal, state or local law.  All
interpretations, determinations and actions by the Committee will
be final and binding upon all persons, including the Company and
the Participants.


V.   Determination of Annual Retainer and Stock Payments

     A.   The Board shall determine the Annual Retainer payable
to all Non-Employee Directors of the Company.

     B.   Each director who is a Non-Employee Director
immediately following the date of the Company's Annual Meeting of
Stockholders shall receive on the fifteenth business day
following the Annual Meeting a Stock Payment of 1,000 shares of
Common Stock as a portion of the Annual Retainer payable to such
director for the Plan Year in which such date occurs.
Certificates evidencing the shares of Common Stock constituting
Stock Payments shall be registered in the respective names of the
Participants and shall be issued to each Participant.  The cash
portion of the Annual Retainer shall be paid to Non-Employee
Directors at such times and in such manner as may be determined
by the Board of Directors.

     C.   Any director may decline a Stock Payment for any Plan
Year; provided, however, that no cash compensation shall be paid
in lieu thereof.  Any director who declines a Stock Payment must
do so in writing prior to the performance of any services as a
Non-Employee Director for the Plan Year to which such Stock
Payment relates.

     D.   No Non-Employee Director shall be required to forfeit
or otherwise return any shares of Common Stock issued as a Stock
Payment pursuant to the Plan (including any shares of Common
Stock received as a result of an election under Section VI)
notwithstanding any change in status of such Non-Employee
Director which renders him ineligible to continue as a
Participant in the Plan.  Any person who is a Non-Employee
Director immediately following the Company's Annual Meeting of
Stockholders shall be entitled to receive a Stock Payment as a
portion of the applicable Annual Retainer.


VI.  Election to Increase Amount of Stock Payment

     In lieu of receiving the cash portion of the Annual Retainer
for any Plan Year, a Participant may make a written election to
reduce the cash portion of such Annual Retainer by a specified
dollar amount and have such amount applied to purchase additional
shares of Common Stock of the Company.  The election shall be
made on a form provided by the Committee and must be returned to
the Committee on or before the last business day of the year
prior to the year in which the election is to be effective.  The
election form shall state the amount by which the Participant
desires to reduce the cash portion of the Annual Retainer, which
shall be applied toward the purchase of Common Stock; provided,
however, that no fractional shares may be purchased.  Stock to be
delivered to Participants pursuant to this election shall be
delivered in December of each year.  Cash in lieu of any
fractional share shall be paid to the Participant.  An election
shall continue in effect until changed or revoked by the
Participant.  No Participant shall be allowed to change or revoke
any election for the then current year, but may change an
election for any subsequent Plan Year.  All shares of Common
Stock received pursuant to an election under this Article VI must
be held by a Participant for six months after receipt thereof.


VII. Adjustment For Changes in Capitalization

     If the outstanding shares of Common Stock of the Company are
increased, decreased or exchanged for a different number or kind
of shares or other securities, or if additional shares or new or
different shares or other securities are distributed with respect
to such shares of Common Stock or other securities, through
merger, consolidation, sale of all or substantially all of the
property of the Company, reorganization or recapitalization,
reclassification, stock dividend, stock split, reverse stock
split, combinations of shares, rights offering, distribution of
assets or other distribution with respect to such shares of
Common Stock or other securities or other change in the corporate
structure or shares of Common Stock, the number of shares to be
granted annually, the maximum number of shares and/or the kind of
shares that may be issued under the Plan shall be appropriately
adjusted by the Committee.  Any determination by the Committee as
to any such adjustment will be final, binding and conclusive.
The maximum number of shares issuable under the Plan as a result
of any such adjustment shall be rounded down to the nearest whole
share.


VIII. Amendment and Termination of Plan

     A.   The Board will have the power, in its discretion, to
amend, suspend or terminate the Plan at any time; provided,
however, that no amendment which requires stockholder approval in
order for the Plan to continue to comply with Rule 16b-3 under
the Exchange Act, including any successor to such Rule, shall be
effective unless such amendment shall be approved by the
requisite vote of the stockholders of the Company entitled to
vote thereon.

     B.   Notwithstanding the foregoing, any provision of the
Plan that either states the amount and price of securities to be
issued under the Plan and specifies the price and timing of such
issuances, or sets forth a formula that determines the amount,
price and timing of such issuances, shall not be amended more
than once every six months, other than to comport with changes in
the Internal Revenue Code, the Employee Retirement Income
Security Act, or the rules thereunder.


IX.  Effective Date and Duration of the Plan

     The Plan will become effective upon the Effective Date, and
shall remain in effect, subject to the right of the Board of
Directors to terminate the Plan at any time pursuant to Section
VIII, until all shares subject to the Plan have been purchased or
acquired according to the Plan's provisions.


X.   Miscellaneous Provisions

     A.   Continuation of Directors in Same Status

     Nothing in the Plan or any action taken pursuant to the Plan
shall be construed as creating or constituting evidence of any
agreement or understanding, express or implied, that the Company
will retain a Non-Employee Director as a director or in any other
capacity for any period of time or at a particular retainer or
other rate of compensation, as conferring upon any Participant
any legal or other right to continue as a director or in any
other capacity, or as limiting, interfering with or otherwise
affecting the right of the Company to terminate a Participant in
his capacity as a director or otherwise at any time for any
reason, with or without cause, and without regard to the effect
that such termination might have upon him as a Participant under
the Plan.

     B.   Compliance with Government Regulations

     Neither the Plan nor the Company shall be obligated to issue
any shares of Common Stock pursuant to the Plan at any time
unless and until all applicable requirements imposed by any
federal and state securities and other laws, rules and
regulations, by any regulatory agencies or by any stock exchanges
upon which the Common Stock may be listed have been fully met.
As a condition precedent to any issuance of shares of Common
Stock and delivery of certificates evidencing such shares
pursuant to the Plan, the Board or the Committee may require a
Participant to take any such action and to make any such
covenants, agreements and representations as the Board or the
Committee, as the case may be, in its discretion deems necessary
or advisable to ensure compliance with such requirements.  The
Company shall in no event be obligated to register the shares of
Common Stock deliverable under the Plan pursuant to the
Securities Act of 1933, as amended, or to qualify or register
such shares under any securities laws of any state upon their
issuance under the Plan or at any time thereafter, or to take any
other action in order to cause the issuance and delivery of such
shares under the Plan or any subsequent offer, sale or other
transfer of such shares to comply with any such law, regulation
or requirement.  Participants are responsible for complying with
all applicable federal and state securities and other laws, rules
and regulations in connection with any offer, sale or other
transfer of the shares of Common Stock issued under the Plan or
any interest therein including, without limitation, compliance
with the registration requirements of the Securities Act of 1933,
as amended (unless an exemption therefrom is available), or with
the provisions of Rule 144 promulgated thereunder, if applicable,
or any successor provisions.  Certificates for shares of Common
Stock may be legended as the Committee shall deem appropriate.

     C.   Nontransferability of Rights

     No Participant shall have the right to assign the right to
receive any Stock Payment or any other right or interest under
the Plan, contingent or otherwise, or to cause or permit any
encumbrance, pledge or charge of any nature to be imposed on any
such Stock Payment (prior to the issuance of stock certificates
evidencing such Stock Payment) or any such right or interest.

     D.   Severability

     In the event that any provision of the Plan is held invalid,
void or unenforceable, the same shall not affect, in any respect
whatsoever, the validity of any other provision of the Plan.

     E.   Governing Law

     To the extent not preempted by Federal law, the Plan shall
be governed by the laws of the State of North Dakota.




</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-12
<SEQUENCE>7
<FILENAME>exh12.txt
<DESCRIPTION>COMPUTATION OF RATIO OF EARNINGS
<TEXT>

                        MDU RESOURCES GROUP, INC.
             COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
          AND COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

                                  Years Ended December 31,
                          2001      2000      1999      1998      1997
                                     (In thousands of dollars)
  Earnings Available for
   Fixed Charges:

  Net Income per
   Consolidated
   Statements of
   Income             $155,849  $111,028  $ 84,080  $ 34,107  $ 54,617

  Income Taxes          98,341    69,650    49,310    17,485    30,743
                       254,190   180,678   133,390    51,592    85,360

  Rents (a)              6,561     3,952     2,018     1,749     1,249

  Interest (b)          51,201    51,801    36,539    31,587    33,047

  Total Earnings
   Available for
   Fixed Charges      $311,952  $236,431  $171,947  $ 84,928  $119,656

  Preferred Dividend
   Requirements       $    762  $    766  $    772  $    777  $    782

  Ratio of Income
   Before Income
   Taxes to Net
   Income                 163%      163%      159%      151%      156%

  Preferred Dividend
   Factor on Pretax
   Basis                 1,242     1,249     1,227     1,173     1,220

  Fixed Charges (c)     57,762    55,753    38,557    33,336    34,296

  Combined Fixed
   Charges and
   Preferred Stock
   Dividends          $ 59,004  $ 57,002  $ 39,784  $ 34,509  $ 35,516

  Ratio of Earnings
   to Fixed Charges       5.4x      4.2x      4.5x      2.5x      3.5x

  Ratio of Earnings
    to Combined
    Fixed Charges
    and Preferred
   Stock Dividends        5.3x      4.1x      4.3x      2.5x      3.4x

(a)  Represents portion (33 1/3%) of rents which is estimated to
     approximately constitute the return to the lessors on their
     investment in leased premises.

(b)  Represents interest and amortization of debt discount and expense
     on all indebtedness and excludes amortization of gains or losses
     on reacquired debt which, under the Uniform System of Accounts, is
     classified as a reduction of, or increase in, interest expense in
     the Consolidated Statements of Income.

(c)  Represents rents and interest, both as defined above.


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13
<SEQUENCE>8
<FILENAME>annualexh13.txt
<DESCRIPTION>SELECTED FINANCIAL AND SUPPLEMENTARY DATA
<TEXT>

                       MDU RESOURCES GROUP, INC.


Report of Management
The management of MDU Resources Group, Inc. is responsible for the
preparation, integrity and objectivity of the financial information
contained in the consolidated financial statements and elsewhere in
this Annual Report.  The financial statements have been prepared in
conformity with accounting principles generally accepted in the United
States as applied to the company's regulated and nonregulated
businesses and necessarily include some amounts that are based on
informed judgments and estimates of management.

To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting
controls designed to provide assurance, on a cost-effective basis, that
transactions are carried out in accordance with management's
authorizations and that assets are safeguarded against loss from
unauthorized use or disposition.  The system includes an organizational
structure which provides an appropriate segregation of
responsibilities, effective selection and training of personnel,
written policies and procedures and periodic reviews by the Internal
Auditing Department.  In addition, the company has a policy which
requires all employees to acknowledge their responsibility for ethical
conduct.  Management believes that these measures provide for a system
that is effective and reasonably assures that all transactions are
properly recorded for the preparation of financial statements.
Management modifies and improves its system of internal accounting
controls in response to changes in business conditions.  The company's
Internal Auditing Department is charged with the responsibility for
determining compliance with company procedures.

The Board of Directors, through its audit committee which is comprised
entirely of outside directors, oversees management's responsibilities
for financial reporting.  The audit committee meets regularly with
management, the internal auditors and Arthur Andersen LLP, independent
public accountants, to discuss auditing and financial matters and to
assure that each is carrying out its responsibilities.  The internal
auditors and Arthur Andersen LLP have full and free access to the audit
committee, without management present, to discuss auditing, internal
accounting control and financial reporting matters.

Arthur Andersen LLP is engaged to express an opinion on the financial
statements.  Their audit is conducted in accordance with auditing
standards generally accepted in the United States and includes
examining, on a test basis, supporting evidence, assessing the
company's accounting principles used and significant estimates made by
management and evaluating the overall financial statement presentation
to the extent necessary to allow them to report on the fairness, in all
material respects, of the financial condition and operating results of
the company.


/s/ Martin A. White                      /s/ Warren L. Robinson
Martin A. White                          Warren L. Robinson
Chairman of the Board                    Executive Vice President
President and Chief                      Treasurer and Chief
Executive Officer                        Financial Officer


                   CONSOLIDATED STATEMENTS OF INCOME
                       MDU RESOURCES GROUP, INC.

Years ended December 31,               2001        2000         1999
                            (In thousands, except per share amounts)

Operating revenues               $2,223,632   $1,873,671  $1,279,809

Operating expenses:
  Fuel and purchased power           57,393       54,114      51,802
  Purchased natural gas sold        529,356      634,277     349,215
  Operation and maintenance       1,168,271      812,600     604,014
  Depreciation, depletion and
    amortization                    139,917      110,888      81,818
  Taxes, other than income           55,427       44,805      33,209
                                  1,950,364    1,656,684   1,120,058

Operating income                    273,268      216,987     159,751

Other income -- net                  26,821       11,724       9,645

Interest expense                     45,899       48,033      36,006

Income before income taxes          254,190      180,678     133,390

Income taxes                         98,341       69,650      49,310
Net income                          155,849      111,028      84,080

Dividends on preferred stocks           762          766         772
Earnings on common stock         $  155,087   $  110,262  $   83,308
Earnings per common share --
  basic                          $     2.31   $     1.80  $     1.53
Earnings per common share --
  diluted                        $     2.29   $     1.80  $     1.52
Dividends per common share       $      .90   $      .86  $      .82
Weighted average common shares
  outstanding -- basic               67,272       61,090      54,615
Weighted average common shares
  outstanding -- diluted             67,869       61,390      54,870

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

                      CONSOLIDATED BALANCE SHEETS
                       MDU RESOURCES GROUP, INC.

December 31,                                         2001       2000
                  (In thousands, except shares and per share amount)
ASSETS
Current assets:
  Cash and cash equivalents                    $   41,811 $   36,512
  Receivables, net                                285,081    342,354
  Inventories                                      95,341     64,017
  Deferred income taxes                            18,973      8,048
  Prepayments and other current assets             40,286     29,355
                                                  481,492    480,286
Investments                                        38,198     41,380
Property, plant and equipment                   2,756,695  2,496,123
  Less accumulated depreciation,
    depletion and amortization                    947,377    895,109
                                                1,809,318  1,601,014
Deferred charges and other assets                 294,063    190,279

                                               $2,623,071 $2,312,959

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
  Short-term borrowings (Note 5)               $      --- $    8,000
  Long-term debt and preferred
    stock due within one year                      11,185     19,695
  Accounts payable                                110,649    171,929
  Taxes payable                                    11,826     10,437
  Dividends payable                                16,108     14,423
  Other accrued liabilities                        95,559     59,989
                                                  245,327    284,473
Long-term debt (Note 6)                           783,709    728,166
Deferred credits and other liabilities:
  Deferred income taxes                           342,412    281,000
  Other liabilities                               125,552    121,860
                                                  467,964    402,860
Preferred stock subject to mandatory
  redemption (Note 7)                               1,300      1,400
Commitments and contingencies (Notes 12, 14 and 15)
Stockholders' equity:
  Preferred stocks (Note 7)                        15,000     15,000
  Common stockholders' equity:
    Common stock (Note 8)
      Authorized -- 150,000,000 shares,
                    $1.00 par value
      Issued -- 70,016,851 shares in 2001 and
                65,267,567 shares in 2000          70,017     65,268
    Other paid-in capital                         646,521    518,771
    Retained earnings                             394,641    300,647
    Accumulated other comprehensive income          2,218        ---
    Treasury stock at cost - 239,521 shares        (3,626)    (3,626)
      Total common stockholders' equity         1,109,771    881,060
   Total stockholders' equity                   1,124,771    896,060

                                               $2,623,071 $2,312,959

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


<TABLE>
          CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
                         MDU RESOURCES GROUP, INC.
<CAPTION>
Years ended December 31, 2001, 2000 and 1999
                                                                 Accumu-
                                                                   lated
                                                                   Other
                                                 Other           Compre-
                              Common Stock     Paid-in  Retained hensive     Treasury Stock
                            Shares    Amount   Capital  Earnings  Income    Shares    Amount       Total
                                                   (In thousands, except shares)
<S>
Balance at              <C>         <C>       <C>       <C>       <C>     <C>        <C>      <C>
 December 31, 1998      53,272,951  $177,399  $171,486  $205,583  $  ---  (239,521)  $(3,626) $  550,842
 Net income                    ---       ---       ---    84,080     ---       ---       ---      84,080
 Dividends on
  preferred stocks             ---       ---       ---      (772)    ---       ---       ---        (772)
 Dividends on
  common stock                 ---       ---       ---   (45,322)    ---       ---       ---     (45,322)
 Reduction in par
  value of common
  stock                        ---  (124,126)  124,126       ---     ---       ---       ---         ---
 Issuance of
  common stock, net      4,004,964     4,005    76,700       ---     ---       ---       ---      80,705

Balance at
 December 31, 1999      57,277,915    57,278   372,312   243,569     ---  (239,521)   (3,626)    669,533
 Net income                    ---       ---       ---   111,028     ---       ---       ---     111,028
 Dividends on
  preferred stocks             ---       ---       ---      (766)    ---       ---       ---        (766)
 Dividends on
  common stock                 ---       ---       ---   (53,184)    ---       ---       ---     (53,184)
 Issuance of
  common stock, net      7,989,652     7,990   146,459       ---     ---       ---       ---     154,449

Balance at
 December 31, 2000      65,267,567    65,268   518,771   300,647     ---  (239,521)   (3,626)    881,060
 Comprehensive income
  Net income                   ---       ---       ---   155,849     ---       ---       ---     155,849
  Other comprehensive
  income
   Net unrealized gain on
   derivative instruments
   qualifying as hedges:
    Unrealized loss on
     derivative instruments
     at January 1, 2001,
     due to cumulative
     effect of a change in
     accounting principle,
     net of tax of $3,970      ---       ---       ---       ---  (6,080)      ---       ---      (6,080)
    Net unrealized gain on
     derivative instruments
     arising during the
     period, net of tax
     of $1,448                 ---       ---       ---       ---   2,218       ---       ---       2,218
    Reclassification
     adjustment for losses
     on derivative
     instruments included
     in net income, net of
     tax of $3,970             ---       ---       ---       ---   6,080       ---       ---       6,080
   Net unrealized gain on
   derivative instruments
   qualifying as hedges        ---       ---       ---       ---   2,218       ---       ---       2,218
 Total comprehensive
 income                        ---       ---       ---       ---     ---       ---       ---     158,067
 Dividends on
  preferred stocks             ---       ---       ---      (762)    ---       ---       ---        (762)
 Dividends on
  common stock                 ---       ---       ---   (61,093)    ---       ---       ---     (61,093)
 Issuance of
  common stock, net      4,749,284     4,749   127,750       ---     ---       ---       ---     132,499

Balance at
 December 31, 2001      70,016,851  $ 70,017  $646,521  $394,641  $2,218  (239,521)  $(3,626) $1,109,771

<FN>
The accompanying notes are an integral part of these consolidated statements.
</FN>
</TABLE>

            CONSOLIDATED STATEMENTS OF CASH FLOWS
                         MDU RESOURCES GROUP, INC.

Years ended December 31,                 2001        2000       1999
                                                (In thousands)

Operating activities:
  Net income                         $155,849   $ 111,028   $ 84,080
  Adjustments to reconcile net income
  to net cash provided by operating
  activities:
    Depreciation, depletion and
      amortization                    139,917     110,888     81,818
    Deferred income taxes and
      investment tax credit            21,014      36,530     15,704
    Changes in current assets and
      liabilities, net of acquisitions:
      Receivables                     127,267    (117,449)   (12,310)
      Inventories                     (26,540)      9,578    (13,460)
      Other current assets             (2,792)     (3,514)    (4,190)
      Accounts payable                (90,576)     61,021     12,492
      Other current liabilities        34,331      (3,821)    (8,972)
    Other noncurrent changes           (9,916)      2,701       (289)
  Net cash provided by operating
    activities                        348,554     206,962    154,873

Investing activities:
 Capital expenditures including
   acquisitions of businesses        (382,285)   (408,826)  (170,510)
 Net proceeds from sale or
   disposition of property             51,641      11,000     16,660
 Net capital expenditures            (330,644)   (397,826)  (153,850)
 Sale of natural gas available
   under repurchase commitment            ---         ---      1,330
 Investments                            2,760       2,102        (99)
 Additions to notes receivable        (23,813)     (5,000)   (35,907)
 Proceeds from notes receivable         4,000       4,000        ---
 Net cash used in investing
   activities                        (347,697)   (396,724)  (188,526)

Financing activities:
 Net change in short-term borrowings   (8,000)     (7,242)    (6,585)
 Issuance of long-term debt           122,283     192,162    154,546
 Repayment of long-term debt         (115,062)    (29,349)   (18,714)
 Retirement of preferred stock           (100)       (100)      (100)
 Proceeds from issuance of
   common stock, net                   67,176      47,249      3,184
 Retirement of natural gas
   repurchase commitment                  ---         ---    (14,296)
 Dividends paid                       (61,855)    (53,950)   (46,094)
 Net cash provided by
   financing activities                 4,442     148,770     71,941

Increase (decrease) in cash
  and cash equivalents                  5,299     (40,992)    38,288
Cash and cash equivalents --
  beginning of year                    36,512      77,504     39,216
Cash and cash equivalents --
  end of year                        $ 41,811   $  36,512   $ 77,504


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



                 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                          MDU RESOURCES GROUP, INC.


NOTE 1

Summary of Significant Accounting Policies

Basis of presentation

The consolidated financial statements of MDU Resources Group, Inc. and

its subsidiaries (company) include the accounts of the following

segments:  electric, natural gas distribution, utility services,

pipeline and energy services, natural gas and oil production, and

construction materials and mining.  The electric and natural gas

distribution segments and a portion of the pipeline and energy services

segment are regulated.  The company's nonregulated operations include

the utility services, natural gas and oil production, and construction

materials and mining segments, and a portion of the pipeline and energy

services segment.  For further descriptions of the company's business

segments see Note 10.  The statements also include the ownership

interests in the assets, liabilities and expenses of two jointly owned

electric generation stations.



The company's regulated businesses are subject to various state and

federal agency regulation.  The accounting policies followed by these

businesses are generally subject to the Uniform System of Accounts of

the Federal Energy Regulatory Commission (FERC).  These accounting

policies differ in some respects from those used by the company's

nonregulated businesses.



The company's regulated businesses account for certain income and

expense items under the provisions of Statement of Financial Accounting

Standards No. 71, "Accounting for the Effects of Regulation" (SFAS

No. 71).  SFAS No. 71 requires these businesses to defer as regulatory

assets or liabilities certain items that would have otherwise been

reflected as expense or income, respectively, based on the expected

regulatory treatment in future rates.  The expected recovery or

flowback of these deferred items is generally based on specific

ratemaking decisions or precedent for each item.  Regulatory assets and

liabilities are being amortized consistently with the regulatory

treatment established by the FERC and the applicable state public

service commissions.  See Note 2 for more information regarding the

nature and amounts of these regulatory deferrals.



Prior to the sale of the company's coal operations as discussed in

Note 10, intercompany coal sales, which were made at prices

approximately the same as those charged to others, and the related

utility fuel purchases are not eliminated in accordance with the

provisions of SFAS No. 71.  All other significant intercompany balances

and transactions have been eliminated in consolidation.



Allowance for doubtful accounts

The company's allowance for doubtful accounts as of December 31, 2001

and 2000, was $5.8 million and $4.1 million, respectively.



Property, plant and equipment

Additions to property, plant and equipment are recorded at cost when

first placed in service.  When regulated assets are retired, or

otherwise disposed of in the ordinary course of business, the original

cost and cost of removal, less salvage, is charged to accumulated

depreciation.  With respect to the retirement or disposal of all other

assets, except for natural gas and oil production properties as

described below, the resulting gains or losses are recognized as a

component of income.  The company is permitted to capitalize an

allowance for funds used during construction (AFUDC) on regulated

construction projects and to include such amounts in rate base when the

related facilities are placed in service.  In addition, the company

capitalizes interest, when applicable, on certain construction projects

associated with its other operations.  The amount of AFUDC and interest

capitalized was $6.6 million, $5.2 million and $1.7 million in 2001,

2000 and 1999, respectively.  Generally, property, plant and equipment

are depreciated on a straight-line basis over the average useful lives

of the assets, except for natural gas and oil production properties as

described below.



Goodwill and other intangible assets

The excess of the cost over the fair value of net assets of purchased

businesses is recorded as goodwill and was being amortized on a

straight-line basis over estimated useful lives for recorded goodwill

in place at June 30, 2001.  However, Statement of Financial Accounting

Standards No. 142, "Goodwill and Other Intangible Assets" (SFAS

No. 142), which the company adopted as of January 1, 2002, as discussed

later in Note 1, requires the discontinuance of goodwill amortization

for the company's recorded goodwill at June 30, 2001, on January 1,

2002.  Goodwill acquired after June 30, 2001, was subject immediately

to the nonamortization provisions of SFAS No. 142.


Goodwill, net of accumulated amortization, was $174.2 million and

$91.4 million as of December 31, 2001 and 2000, respectively.  Goodwill

is included in deferred charges and other assets.  Goodwill

amortization expense was $4.8 million, $7.0 million and $2.0 million

for 2001, 2000 and 1999, respectively.



Impairment of long-lived assets and intangibles

The company reviews the carrying values of its long-lived assets,

including goodwill and identifiable intangibles, whenever events or

changes in circumstances indicate that such carrying values may not be

recoverable and annually for goodwill as required by SFAS No. 142.  The

determination of whether an impairment has occurred is based on an

estimate of undiscounted future cash flows attributable to the assets,

compared to the carrying value of the assets.  If an impairment has

occurred, the amount of the impairment recognized is determined by

estimating the fair value of the assets and recording a loss if the

carrying value is greater than the fair value.  In 2000, the company

experienced significant changes in market conditions at one of its

energy marketing operations, which negatively affected the fair value

of the assets at that operation.  Due to the significance of the

decline, the company recorded an impairment charge against goodwill of

$3.9 million after-tax in 2000.  The amount related to this impairment

is included in depreciation, depletion and amortization.  Excluding

this impairment, no other long-lived assets or intangibles have been

impaired and accordingly, no other impairment losses have been recorded

in 2001, 2000 and 1999.  Unforeseen events and changes in circumstances

could require the recognition of other impairment losses at some future

date.



Impairment testing of natural gas and oil properties

The company uses the full-cost method of accounting for its natural gas

and oil production activities.  Under this method, all costs incurred

in the acquisition, exploration and development of natural gas and oil

properties are capitalized and amortized on the units of production

method based on total proved reserves.  Any conveyances of properties,

including gains or losses on abandonments of properties, are treated as

adjustments to the cost of the properties with no gain or loss

recognized.  Capitalized costs are subject to a "ceiling test" that

limits such costs to the aggregate of the present value of future net

revenues of proved reserves based on single point in time spot market

prices, as mandated under the rules of the Securities and Exchange

Commission, and the lower of cost or fair value of unproved properties.

Future net revenue is estimated based on end-of-quarter spot market

prices adjusted for contracted price changes.  If capitalized costs

exceed the full-cost ceiling at the end of any quarter, a permanent

noncash write-down is required to be charged to earnings in that

quarter unless subsequent price changes eliminate or reduce an

indicated write-down.



Due to abnormally low spot natural gas prices that existed on the last

trading day of the third quarter of 2001, the company's capitalized

costs under the full-cost method of accounting exceeded the full-cost

ceiling at September 30, 2001.  The lower natural gas prices were

largely attributable to a sharp decline in nationwide spot market

prices, especially natural gas prices in the Rocky Mountain region,

over a relatively short period of time following the terrorist attacks

on New York and Washington, D.C. on September 11, 2001, and prior to

October 1, 2001.  Oil prices likewise experienced a sharp drop during

this same period.  The company believes the decline in natural gas

prices did not reflect the economics of its production assets in that

natural gas prices actually being received by the company at the end of

the third quarter of 2001 were significantly higher than the spot

market prices at that time.  In addition, historic natural gas prices

have also generally been much higher and only a small portion of the

company's natural gas is sold using spot market pricing.  As of

September 30, 2001, the capitalized costs exceeded the full-cost

ceiling and would have resulted in a write-down of the company's

natural gas and oil properties in the amount of approximately $32

million after-tax.  However, subsequent to September 30, 2001, natural

gas prices both nationwide and in the Rocky Mountain region increased

significantly, thereby eliminating the need for a write-down of the

company's natural gas and oil producing properties.



At December 31, 2001, the company's full-cost ceiling exceeded the

company's capitalized cost.  However, sustained downward movements in

natural gas and oil prices subsequent to December 31, 2001, could

result in a future write-down of the company's natural gas and oil

properties.



Natural gas in underground storage

Natural gas in underground storage for the company's regulated

operations is carried at cost using the last-in, first-out method.  The

portion of the cost of natural gas in underground storage expected to

be used within one year is included in inventories and amounted to

$28.6 million and $11.0 million at December 31, 2001 and 2000,

respectively.  The remainder of natural gas in underground storage is

included in property, plant and equipment and was $43.1 million and

$43.6 million at December 31, 2001 and 2000, respectively.



Inventories

Inventories, other than natural gas in underground storage for the

company's regulated operations, consist primarily of materials and

supplies of $22.5 million and $20.4 million, aggregates held for resale

of $31.1 million and $22.7 million and other inventories of $13.1

million and $9.9 million as of December 31, 2001 and 2000,

respectively.  These inventories are stated at the lower of average

cost or market.



Revenue recognition

Revenue is recognized when the earnings process is complete, as

evidenced by an agreement between the customer and the company, when

delivery has occurred or services have been rendered, when the fee is

fixed or determinable and when collection is probable.  The company

recognizes utility revenue each month based on the services provided to

all utility customers during the month.  The company recognizes

construction contract revenue at its construction businesses using the

percentage-of-completion method as discussed below.  The company

recognizes revenue from natural gas and oil production activities only

on that portion of production sold and allocable to the company's

ownership interest in the related well.  The company generally

recognizes all other revenues when services are rendered or goods are

delivered.



Percentage-of-completion method

The company recognizes construction contract revenue from fixed price

and modified fixed price construction contracts at its construction

businesses using the percentage-of-completion method, measured by the

percentage of costs incurred to date to estimated total costs for each

contract.  Costs in excess of billings on uncompleted contracts of

$29.7 million and $13.9 million for the years ending December 31, 2001

and 2000, respectively, represents revenues recognized in excess of

amounts billed and is included in accounts receivable.  Billings in

excess of costs on uncompleted contracts of $17.3 million and $8.0

million for the years ending December 31, 2001 and 2000, respectively,

represents billings in excess of revenues recognized and are included

in accounts payable.  Also included in accounts receivable are amounts

representing balances billed but not paid by customers under retainage

provisions in contracts which amounted to $20.5 million and

$13.7 million as of December 31, 2001 and 2000, respectively.



Advertising

The company expenses advertising costs as incurred and the amount of

advertising expense for the years 2001, 2000 and 1999, was $2.9

million, $2.0 million and $1.3 million, respectively.



Natural gas costs recoverable or refundable through rate adjustments

Under the terms of certain orders of the applicable state public

service commissions, the company is deferring natural gas commodity,

transportation and storage costs which are greater or less than amounts

presently being recovered through its existing rate schedules.  Such

orders generally provide that these amounts are recoverable or

refundable through rate adjustments within a period ranging from 24

months to 28 months from the time such costs are paid.  Natural gas

costs refundable through rate adjustments amounted to $27.7 million and

$8.8 million for the years ended December 31, 2001 and 2000,

respectively, and are included in other accrued liabilities.



Income taxes

The company provides deferred federal and state income taxes on all

temporary differences.  Excess deferred income tax balances associated

with the company's rate-regulated activities resulting from the

company's adoption of SFAS No. 109, "Accounting for Income Taxes," have

been recorded as a regulatory liability and are included in other

accrued liabilities.  These regulatory liabilities are expected to be

reflected as a reduction in future rates charged customers in

accordance with applicable regulatory procedures.


The company uses the deferral method of accounting for investment tax

credits and amortizes the credits on electric and natural gas

distribution plant over various periods which conform to the ratemaking

treatment prescribed by the applicable state public service

commissions.



Earnings per common share

Basic earnings per common share were computed by dividing earnings on

common stock by the weighted average number of shares of common stock

outstanding during the year.  Diluted earnings per common share were

computed by dividing earnings on common stock by the total of the

weighted average number of shares of common stock outstanding during

the year, plus the effect of outstanding stock options and restricted

stock grants.  For the years ending December 31, 2001 and 1999, 150,630

shares and 76,500 shares, respectively, with an average exercise price

of $36.86 and $23.44, respectively, attributable to the exercise of

outstanding options were excluded from the calculation of diluted

earnings per share because their effect was antidilutive.  For the year

ending December 31, 2000, there were no shares excluded from the

calculation of diluted earnings per share.  For the years ending

December 31, 2001, 2000 and 1999, no adjustments were made to reported

earnings in the computation of earnings per share.  Common stock

outstanding includes issued shares less shares held in treasury.



Use of estimates

The preparation of financial statements in conformity with accounting

principles generally accepted in the United States requires the company

to make estimates and assumptions that affect the reported amounts of

assets and liabilities and disclosure of contingent assets and

liabilities at the date of the financial statements and the reported

amounts of revenues and expenses during the reporting period.

Estimates are used for such items as property depreciable lives, tax

provisions, uncollectible accounts, environmental and other loss

contingencies, accumulated provision for revenues subject to refund,

costs on construction contracts, unbilled revenues and actuarially

determined benefit costs.  As additional information becomes available,

or actual amounts are determinable, the recorded estimates are revised.

Consequently, operating results can be affected by revisions to prior

accounting estimates.



Cash flow information

Cash expenditures for interest and income taxes were as follows:


Years ended December 31,                    2001       2000       1999
                                                 (In thousands)
Interest, net of amount capitalized      $42,267    $41,912    $30,772
Income taxes                             $75,284    $30,930    $32,723


The company considers all highly liquid investments purchased with an

original maturity of three months or less to be cash equivalents.



Reclassifications

Certain reclassifications have been made in the financial statements

for prior years to conform to the current presentation.  Such

reclassifications had no effect on net income or stockholders' equity

as previously reported.



New accounting pronouncements

In June 2001, the Financial Accounting Standards Board (FASB) approved

Statement of Financial Accounting Standards No. 141, "Business

Combinations" (SFAS No. 141).  SFAS No. 141 requires that all business

combinations be accounted for using the purchase method of accounting.

The use of the pooling-of-interest method of accounting for business

combinations is prohibited.  The provisions of SFAS No. 141 apply to

all business combinations initiated after June 30, 2001.  The

company is accounting for business combinations after June 30, 2001, in

accordance with SFAS No. 141.


In June 2001, the FASB approved SFAS No. 142.  SFAS No. 142 changes the

accounting for goodwill and intangible assets and requires that

goodwill no longer be amortized but be tested for impairment at least

annually at the reporting unit level in accordance with SFAS No. 142.

Recognized intangible assets with determinable useful lives should be

amortized over their useful life and reviewed for impairment in

accordance with Statement of Financial Accounting Standards No. 144,

"Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS

No. 144).  The provisions of SFAS No. 142 are effective for fiscal

years beginning after December 15, 2001, except for provisions related

to the nonamortization and amortization of goodwill and intangible

assets acquired after June 30, 2001, which were subject immediately to

the provisions of SFAS No. 142.  The company adopted SFAS No. 142 on

January 1, 2002.  The company ceased amortization of its recorded

goodwill at June 30, 2001, on January 1, 2002.  Goodwill at each

reporting unit will be tested for impairment as of January 1, 2002.

The company will perform this transitional goodwill impairment test

within six months of the date of adoption of SFAS No. 142.  However,

the amounts used in the transitional goodwill impairment test shall be

measured as of January 1, 2002.  The company believes the adoption of

the goodwill impairment provisions of SFAS No. 142 will not have a

material effect on its financial position or results of operations.


In June 2001, the FASB approved Statement of Financial Accounting

Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS

No. 143).  SFAS No. 143 requires entities to record the fair value of a

liability for an asset retirement obligation in the period in which it

is incurred.  When the liability is initially recorded, the entity

capitalizes a cost by increasing the carrying amount of the related

long-lived asset.  Over time, the liability is accreted to its present

value each period, and the capitalized cost is depreciated over the

useful life of the related asset.  Upon settlement of the liability, an

entity either settles the obligation for the recorded amount or incurs

a gain or loss upon settlement.  SFAS No. 143 is effective for fiscal

years beginning after June 15, 2002.  The company will adopt SFAS No.

143 on January 1, 2003, but has not yet quantified the effects of

adopting SFAS No. 143 on its financial position or results of

operations.


In August 2001, the FASB approved SFAS No. 144.  SFAS No. 144

supersedes Statement of Financial Accounting Standards No. 121,

"Accounting for the Impairment of Long-Lived Assets and for Long-Lived

Assets to Be Disposed Of."  SFAS No. 144 addresses accounting and

reporting for the impairment or disposal of long-lived assets,

including the disposal of a segment of a business.  SFAS No. 144 is

effective for fiscal years beginning after December 15, 2001.  The

company adopted SFAS No. 144 on January 1, 2002.  The adoption of SFAS

No. 144 did not have an effect on the company's financial position or

results of operations.


The company adopted Statement of Financial Accounting Standards No.

133, "Accounting for Derivative Instruments and Hedging Activities"

(SFAS No. 133), amended by Statement of Financial Accounting Standards

No. 137, "Accounting for Derivative Instruments and Hedging Activities -

Deferral of the Effective Date of FASB Statement No. 133" and Statement

of Financial Accounting Standards No. 138, "Accounting for Certain

Derivative Instruments and Certain Hedging Activities" (all such

statements hereinafter referred to as SFAS No. 133) on January 1, 2001.

SFAS No. 133 establishes accounting and reporting standards requiring

that every derivative instrument (including certain derivative

instruments embedded in other contracts) be recorded on the balance

sheet as either an asset or liability measured at its fair value.  SFAS

No. 133 requires that changes in the derivative instrument's fair value

be recognized currently in earnings unless specific hedge accounting

criteria are met.  Special accounting for qualifying hedges allows

derivative gains and losses to offset the related results on the hedged

item in the income statement, and requires that a company must formally

document, designate and assess the effectiveness of transactions that

receive hedge accounting treatment.



SFAS No. 133 requires that as of the date of initial adoption, the

difference between the fair market value of derivative instruments

recorded on the balance sheet and the previous carrying amount of those

derivative instruments be reported in net income or other comprehensive

income (loss), as appropriate, as the cumulative effect of a change in

accounting principle in accordance with APB 20, "Accounting Changes."

On January 1, 2001, the company reported a net-of-tax cumulative-effect

adjustment of $6.1 million in accumulated other comprehensive loss to

recognize at fair value all derivative instruments that are designated

as cash-flow hedging instruments, which the company reflected in

earnings over the 12 months ended December 31, 2001.  The transition to

SFAS No. 133 did not have an effect on the company's net income at

adoption.



Comprehensive income

Upon the adoption of SFAS No. 133 on January 1, 2001, the company

recorded a cumulative-effect adjustment in accumulated other

comprehensive income to recognize all derivative instruments designated

as hedges at fair value.  As of December 31, 2001, the company has

recorded unrealized gains and losses on swap agreements in accordance

with SFAS No. 133.  These amounts are reflected in the Consolidated

Statements of Common Stockholders' Equity.  For additional information

on the adoption of SFAS No. 133, see new accounting pronouncements in

Note 1, and Note 3.  For the years ended December 31, 2000 and 1999,

comprehensive income equaled net income as reported.



NOTE 2

Regulatory Assets and Liabilities

The following table summarizes the individual components of unamortized

regulatory assets and liabilities included in the accompanying

Consolidated Balance Sheets as of December 31:


                                                     2001        2000
                                                      (In thousands)
Regulatory assets:
  Deferred income taxes                          $ 13,417    $    263
  Long-term debt refinancing costs                  6,829       8,125
  Plant costs                                       2,499       2,668
  Postretirement benefit costs                        722         833
  Other                                             5,929       7,052
Total regulatory assets                            29,396      18,941
Regulatory liabilities:
  Natural gas costs refundable
    through rate adjustments                       27,706       8,772
  Taxes refundable to customers                    12,318      11,656
  Plant decommissioning costs                       8,243       7,601
  Reserves for regulatory matters                   7,132       6,087
  Deferred income taxes                             5,661       3,554
  Other                                             5,053       1,193
Total regulatory liabilities                       66,113      38,863
Net regulatory position                          $(36,717)   $(19,922)


As of December 31, 2001, substantially all of the company's regulatory

assets, other than certain deferred income taxes, are being reflected

in rates charged to customers and are being recovered over the next one

to 15 years.



If, for any reason, the company's regulated businesses cease to meet

the criteria for application of SFAS No. 71 for all or part of their

operations, the regulatory assets and liabilities relating to those

portions ceasing to meet such criteria would be removed from the

balance sheet and included in the statement of income as an

extraordinary item in the period in which the discontinuance of SFAS

No. 71 occurs.



NOTE 3

Derivative Instruments

As of December 31, 2001, the company held derivative instruments

designated as cash flow hedging instruments.  All derivative

instruments are recognized on the Consolidated Balance Sheets at fair

value.



Hedging activities

The cash flow hedging instruments in place at December 31, 2001, are

comprised of natural gas and oil price swap agreements.  The objective

for holding the natural gas and oil price swap agreements is to manage

a portion of the market risk associated with fluctuations in the price

of natural gas and oil on the company's forecasted sales of natural gas

and oil production.  The company also entered into an interest rate

swap agreement which expired in the fourth quarter of 2001.  The

objective for holding the interest rate swap agreement was to manage a

portion of the company's interest rate risk on the forecasted issuance

of fixed-rate debt under Centennial Energy Holdings, Inc.'s

(Centennial), a direct wholly owned subsidiary of the company,

commercial paper program.  The company designated each of the natural

gas and oil price swap agreements as a hedge of the forecasted sale of

natural gas and oil production and designated the interest rate swap

agreement as a hedge of the risk of changes in interest rates on the

company's forecasted issuances of fixed-rate debt under Centennial's

commercial paper program.



The company's policy allows the use of derivative instruments as part

of an overall energy price and interest rate risk management program to

efficiently manage and minimize commodity price and interest rate risk.

The company's policy prohibits the use of derivative instruments for

speculating to take advantage of market trends and conditions and the

company has procedures in place to monitor compliance with its

policies.  The company is exposed to credit-related losses in relation

to hedged derivative instruments in the event of nonperformance by

counterparties.  The company has policies and procedures, which

management believes minimize credit-risk exposure.  These policies and

procedures include an evaluation of potential counterparties' credit

ratings, credit exposure limitations, settlement of natural gas and oil

price swap agreements monthly and settlement of interest rate swap

agreements within 90 days.  Accordingly, the company does not

anticipate any material effect to its financial position or results of

operations as a result of nonperformance by counterparties.



Upon the adoption of SFAS No. 133, the company recorded the fair market

value of the natural gas and oil price swap agreements on the company's

Consolidated Balance Sheets.  On an ongoing basis, the company adjusts

its balance sheet to reflect the current fair market value of its swap

agreements.  The related gains or losses on these agreements are

recorded in common stockholders' equity as a component of other

comprehensive income (loss).  At the date the underlying transaction

occurs, the amounts accumulated in other comprehensive income (loss)

are reported in the Consolidated Statements of Income.  To the extent

that the hedges are not effective, the ineffective portion of the

changes in fair market value is recorded directly in earnings.



For the year ended December 31, 2001, the company recognized the

ineffectiveness of all cash flow hedges, which is included in operating

revenues and interest expense for the natural gas and oil price swap

agreements and the interest rate swap agreement, respectively.  For the

year ended December 31, 2001, the amount of ineffectiveness recognized

was immaterial.  For the year ended December 31, 2001, the company did

not exclude any components of the derivative instruments' gain or loss

from the assessment of hedge effectiveness and there were no

reclassifications into earnings as a result of the discontinuance of

hedges.



Gains and losses on derivative instruments that are reclassified from

accumulated other comprehensive income (loss) to current-period

earnings are included in the line item in which the hedged item is

recorded.  As of December 31, 2001, the maximum length of time over

which the company is hedging its exposure to the variability in future

cash flows for forecasted transactions is 12 months and the company

estimates that net gains of approximately $2.2 million will be

reclassified from accumulated other comprehensive income into earnings,

subject to changes in natural gas and oil market prices, within the 12

months between January 1, 2002 and December 31, 2002, as the hedged

transactions affect earnings.


In the event a derivative instrument does not qualify for hedge

accounting because it is no longer highly effective in offsetting

changes in cash flows of a hedged item; or if the derivative instrument

expires or is sold, terminated, or exercised; or if management

determines that designation of the derivative instrument as a hedge

instrument is no longer appropriate, hedge accounting will be

discontinued, and the derivative instrument would continue to be

carried at fair value with changes in its fair value recognized in

earnings.  In these circumstances, the net gain or loss at the time of

discontinuance of hedge accounting would remain in other comprehensive

income (loss) until the period or periods during which the hedged

forecasted transaction affects earnings, at which time the net gain or

loss would be reclassified into earnings.  In the event a cash flow

hedge is discontinued because it is unlikely that a forecasted

transaction will occur, the derivative instrument would continue to be

carried on the balance sheet at its fair value, and gains and losses

that were accumulated in other comprehensive income (loss) would be

recognized immediately in earnings.  The company's policy requires

approval to terminate a hedge agreement prior to its original maturity.



Energy marketing

The company had entered into other derivative instruments that were not

designated as hedges in its energy marketing operations.  In the third

quarter of 2001, the company sold the vast majority of its energy

marketing operations.  The derivative instruments entered into by these

operations prior to the sale in the third quarter of 2001 were natural

gas forward purchase and sale commitments.  These commitments involved

the purchase and sale of natural gas and related delivery of such

commodity.  These operations sought to match natural gas purchases and

sales so that a margin was obtained on the transportation of such

commodity as distinguished from earning a margin on changes in market

prices.  The net change in fair value representing unrealized gains and

losses resulting from changes in market prices on these derivative

instruments was reflected as operating revenues or purchased natural

gas sold.  Net unrealized gains and losses on these derivative

instruments were not material for the years ended December 31, 2001,

2000 and 1999.



NOTE 4

Fair Value of Other Financial Instruments

The estimated fair value of the company's long-term debt and preferred

stock subject to mandatory redemption is based on quoted market prices

of the same or similar issues.  The estimated fair value of the

company's long-term debt and preferred stock subject to mandatory

redemption at December 31 is as follows:



                                  2001                    2000
                       Carrying          Fair    Carrying        Fair
                         Amount         Value      Amount       Value
                                         (In thousands)
Long-term debt         $794,794      $894,652    $747,761    $772,127
Preferred stock
  subject to mandatory
  redemption           $  1,400      $    940    $  1,500    $    927


The fair value of other financial instruments for which estimated fair

value has not been presented is not materially different than the

related carrying amount.



NOTE 5

Short-term Borrowings

The company has unsecured short-term lines of credit from a number of

banks totaling $110 million at December 31, 2001.  These line of credit

agreements provide for bank borrowings against the lines and/or support

for commercial paper issues.  The agreements provide for commitment

fees at varying rates.  There were no amounts outstanding on the short-

term lines of credit at December 31, 2001.  The amount outstanding on

the short-term lines of credit was $8 million at December 31, 2000.

The weighted average interest rate for borrowings outstanding at

December 31, 2000, was 6.6 percent.



NOTE 6

Long-term Debt and Indenture Provisions

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


                                                    2001        2000
                                                     (In thousands)
First mortgage bonds and notes:
  Pollution Control Refunding Revenue
    Bonds, Series 1992,
    6.65%, due June 1, 2022                     $ 20,850    $ 20,850
  Secured Medium-Term Notes,
    Series A at a weighted
    average rate of 7.59%, due on
    dates ranging from October 1, 2004
    to April 1, 2012                             110,000     110,000
Total first mortgage bonds and notes             130,850     130,850
Senior notes at a weighted
  average rate of 7.34%, due on
  dates ranging from July 31, 2002
  to October 30, 2018                            405,200     294,300
Commercial paper at a weighted average
  rate of 2.43%, supported by a revolving
  credit agreement                               219,700     261,350
Revolving line of credit, 4.75%, due
  December 31, 2003                               25,000      46,302
Term credit agreements at a weighted
  average rate of 7.38%, due on dates
  ranging from February 1, 2002
  through December 1, 2013                        11,769      12,731
Pollution control note obligation,
  6.20%, due March 1, 2004                         2,500       2,800
Discount                                            (225)       (572)
Total long-term debt                             794,794     747,761
Less current maturities                           11,085      19,595
Net long-term debt                              $783,709    $728,166


Centennial has a revolving credit agreement with various banks that

supports Centennial's $350 million commercial paper program.  There

were no outstanding borrowings under the Centennial credit agreement at

December 31, 2001.  Under the commercial paper program, $219.7 million

and $261.4 million were outstanding at December 31, 2001 and 2000,

respectively.  The commercial paper borrowings are classified as long

term as Centennial intends to refinance these borrowings on a long-term

basis through continued commercial paper borrowings and as further

supported by the revolving credit agreement, which allows for

subsequent borrowings up to a term of one year.  Centennial intends to

renew this existing credit agreement, which expires September 27, 2002,

on an annual basis.



Centennial has an uncommitted long-term master shelf agreement that

allows for borrowings of up to $300 million.  Under the master shelf

agreement, $210 million was outstanding at December 31, 2001, and

$150 million was outstanding at December 31, 2000.  The amount

outstanding is included in senior notes in the preceding long-term debt

table.



Under a revolving line of credit, the company has $40 million available

as of December 31, 2001.  The amount outstanding under the revolving

line of credit was $25.0 million at December 31, 2001.  At December 31,

2000, the company had $46.3 million outstanding under revolving lines

of credit.



The amounts of scheduled long-term debt maturities for the five years

and thereafter following December 31, 2001, aggregate $11.1 million in

2002; $266.8 million in 2003; $21.9 million in 2004; $70.2 million in

2005; $85.2 million in 2006 and $339.6 million thereafter.



Substantially all of the company's electric and natural gas

distribution properties, with certain exceptions, are subject to the

lien of its Indenture of Mortgage.  Under the terms and conditions of

the Indenture, the company could have issued approximately $305 million

of additional first mortgage bonds at December 31, 2001.  Certain other

debt instruments of the company contain restrictive covenants, all of

which the company is in compliance with at December 31, 2001.



NOTE 7

Preferred Stocks

Preferred stocks at December 31 are as follows:


                                                     2001        2000
                                               (Dollars in thousands)
Authorized:
  Preferred --
    500,000 shares, cumulative,
      par value $100, issuable in series
  Preferred stock A --
    1,000,000 shares, cumulative, without par
      value, issuable in series (none outstanding)
  Preference --
    500,000 shares, cumulative, without par
      value, issuable in series (none outstanding)
Outstanding:
  Subject to mandatory redemption --
    Preferred --
      5.10% Series -- 14,000 shares in 2001
        and 15,000 shares in 2000                 $ 1,400     $ 1,500
  Other preferred stock --
      4.50% Series -- 100,000 shares               10,000      10,000
      4.70% Series -- 50,000 shares                 5,000       5,000
                                                   15,000      15,000
Total preferred stocks                             16,400      16,500
Less sinking fund requirements                        100         100
Net preferred stocks                              $16,300     $16,400


The preferred stocks outstanding are subject to redemption, in whole or

in part, at the option of the company with certain limitations on 30

days notice on any quarterly dividend date on certain series of

preferred stock.



The company is obligated to make annual sinking fund contributions to

retire the 5.10% Series preferred stock.  The redemption prices and

sinking fund requirements, where applicable, are summarized below:


                               Redemption             Sinking Fund
Series                          Price (a)         Shares    Price (a)
Preferred stocks:
  4.50%                          $105 (b)            ---          ---
  4.70%                          $102 (b)            ---          ---
  5.10%                          $102              1,000 (c)     $100
(a) Plus accrued dividends.
(b) These series are redeemable at the sole discretion of the company.
(c) Annually on December 1, if tendered.


In the event of a voluntary or involuntary liquidation, all preferred

stock series holders are entitled to $100 per share, plus accrued

dividends.



The aggregate annual sinking fund amount applicable to preferred stock

subject to mandatory redemption is $100,000 for each of the five years

following December 31, 2001, and $900,000 thereafter.



NOTE 8

Common Stock

At the Annual Meeting of Stockholders held in April 1999, the company's

common stockholders approved an amendment to the Certificate of

Incorporation increasing the authorized number of common shares from 75

million shares to 150 million shares and reducing the par value of the

common stock from $3.33 per share to $1.00 per share.



The company's Automatic Dividend Reinvestment and Stock Purchase Plan

(Stock Purchase Plan) provides participants the opportunity to invest

all or a portion of their cash dividends in shares of the company's

common stock and to make optional cash payments for the same purpose.

Holders of all classes of the company's capital stock, legal residents

in any of the 50 states, and beneficial owners, whose shares are held

by brokers or other nominees through participation by their brokers or

nominees, are eligible to participate in the Stock Purchase Plan.  The

company's 401(k) Retirement Plan (K-Plan), is funded with the company's

common stock.  Since January 1, 1999, the Stock Purchase Plan and K-

Plan have been funded primarily by the purchase of shares of common

stock on the open market, except from January 1, 1999 through March 31,

1999, when shares of authorized but unissued common stock were used to

fund the Stock Purchase Plan.  At December 31, 2001, there were 8.1

million shares of common stock reserved for original issuance under the

Stock Purchase Plan and K-Plan.



In November 1998, the company's Board of Directors declared, pursuant

to a stockholders' rights plan, a dividend of one preference share

purchase right (right) for each outstanding share of the company's

common stock.  Each right becomes exercisable, upon the occurrence of

certain events, for one one-thousandth of a share of Series B

Preference Stock of the company, without par value, at an exercise

price of $125 per one one-thousandth, subject to certain adjustments.

The rights are currently not exercisable and will be exercisable only

if a person or group (acquiring person) either acquires ownership of 15

percent or more of the company's common stock or commences a tender or

exchange offer that would result in ownership of 15 percent or more.

In the event the company is acquired in a merger or other business

combination transaction or 50 percent or more of its consolidated

assets or earnings power are sold, each right entitles the holder to

receive, upon the exercise thereof at the then current exercise price

of the right multiplied by the number of one one-thousandth of a Series

B Preference Stock for which a right is then exercisable, in accordance

with the terms of the rights agreement, such number of shares of common

stock of the acquiring person having a market value of twice the then

current exercise price of the right.  The rights, which expire on

December 31, 2008, are redeemable in whole, but not in part, for a

price of $.01 per right, at the company's option at any time until any

acquiring person has acquired 15 percent or more of the company's

common stock.



The company has stock option plans for directors, key employees and

employees, which grant options to purchase shares of the company's

stock.  The company accounts for these option plans in accordance with

APB Opinion No. 25 under which no compensation expense has been

recognized.  The option exercise price is the market value of the stock

on the date of grant.  Options granted to the key employees

automatically vest after nine years, but the plan provides for

accelerated vesting based on the attainment of certain performance

goals or upon a change in control of the company, and expire 10 years

after the date of grant.  Options granted to directors and employees

vest at date of grant and three years after date of grant,

respectively, and expire 10 years after the date of grant.  In

addition, the company has granted restricted stock awards under a long-

term incentive plan, deferred compensation agreements and a restricted

stock agreement totaling 350,392 shares, 348,021 shares and 105,250

shares in 2001, 2000 and 1999, respectively.  The restricted stock

awards granted vest to the participants at various times ranging from

two years to nine years from date of issuance but certain grants may

vest early based upon the attainment of certain performance goals or

upon a change in control of the company.  The weighted average grant

date fair value of the restricted stock grants was $31.55, $20.81 and

$22.91 in 2001, 2000 and 1999, respectively.  Compensation expense

recognized for restricted stock grants was $4.5 million, $1.6 million

and $722,000 in 2001, 2000 and 1999, respectively.  Under the stock

option plans and long-term incentive plan, the company is authorized to

grant options and restricted stock for up to 9.8 million shares of

common stock and has granted options and restricted stock on 4.8

million shares through December 31, 2001.



Had the company recorded compensation expense for the fair value of

options granted consistent with SFAS No. 123, "Accounting for Stock-

Based Compensation," net income would have been reduced on a pro forma

basis by $3.8 million in 2001, $529,000 in 2000, and $498,000 in 1999.

On a pro forma basis, basic and diluted earnings per share for 2001

would have been reduced by $.06.  On a pro forma basis, there would

have been no effect on basic earnings per share for 2000, and diluted

earnings per share would have been reduced by $.01.  On a pro forma

basis, basic and diluted earnings per share for 1999 would have been

reduced by $.01.



A summary of the status of the stock option plans at December 31, 2001,

2000 and 1999, and changes during the years then ended are as follows:



                            2001                2000               1999
                              Weighted            Weighted           Weighted
                               Average             Average            Average
                              Exercise            Exercise           Exercise
                        Shares   Price      Shares   Price     Shares   Price
Balance at
  beginning of year  1,224,959  $20.61   1,427,262  $19.46  1,516,808  $19.17
Granted              2,693,120   30.14      74,000   20.54     22,500   23.31
Forfeited              (74,282)  27.24     (84,135)  21.18    (57,966)  20.38
Exercised             (371,590)  20.23    (192,168)  11.84    (54,080)  11.95
Balance at end
  of year            3,472,207   27.90   1,224,959   20.61  1,427,262   19.46
Exercisable at
  end of year          770,142  $21.41     129,763  $18.11    301,681  $13.89


Summarized information about stock options outstanding and exercisable

as of December 31, 2001, is as follows:



                            Options Outstanding            Options Exercisable
                                   Remaining   Weighted               Weighted
                                 Contractual    Average                Average
Range of                  Number        Life   Exercise       Number  Exercise
Exercisable Prices   Outstanding    in Years      Price  Exercisable     Price

$10.50 - 17.50            41,966         3.7     $13.36       41,966    $13.36
 17.51 - 24.50           789,371         6.3      21.15      698,176     21.16
 24.51 - 31.50         2,490,240         9.2      29.74          ---       ---
 31.51 - 38.55           150,630         9.2      36.86       30,000     38.55
                       3,472,207                             770,142


The fair value of each option is estimated on the date of grant using

the Black-Scholes option pricing model.  The weighted average fair

value of the options granted and the assumptions used to estimate the

fair value of options are as follows:


                                          2001        2000      1999

Weighted average fair value of
  options at grant date                $  7.38     $  5.07   $  4.82
Weighted average risk-free
  interest rate                           5.19%       6.76%     5.98%
Weighted average expected
  price volatility                       26.05%      23.55%    22.03%
Weighted average expected
  dividend yield                          3.53%       3.84%     4.22%
Expected life in years                       7           7         7



NOTE 9

Income Taxes


Income tax expense is summarized as follows:

Years ended December 31,                  2001        2000      1999
                                                (In thousands)
Current:
  Federal                              $66,211     $27,865   $29,574
  State                                 11,160       5,188     3,874
  Foreign                                  (44)         67       158
                                        77,327      33,120    33,606
Deferred:
  Income taxes --
    Federal                             16,972      29,323    12,902
    State                                4,773       8,060     3,690
  Investment tax credit                   (731)       (853)     (888)
                                        21,014      36,530    15,704
Total income tax expense               $98,341     $69,650   $49,310


Components of deferred tax assets and deferred tax liabilities

recognized in the company's Consolidated Balance Sheets at December 31

are as follows:

                                                      2001      2000
                                                      (In thousands)
Deferred tax assets:
  Regulatory matters                             $  21,000  $  7,650
  Accrued pension costs                              9,349    10,325
  Accrued land reclamation                           1,648     1,941
  Deferred investment tax credit                     1,413     1,697
  Other                                             21,691    18,213
Total deferred tax assets                           55,101    39,826
Deferred tax liabilities:
  Depreciation and basis differences
    on property, plant and equipment               302,103   264,635
  Basis differences on natural gas
    and oil producing properties                    61,684    36,763
  Regulatory matters                                 5,661     3,554
  Other                                              9,092     7,826
Total deferred tax liabilities                     378,540   312,778
Net deferred income tax liability                $(323,439)$(272,952)


The following table reconciles the change in the net deferred income

tax liability from December 31, 2000, to December 31, 2001, to the

deferred income tax expense included in the Consolidated Statements of

Income:


                                                                2001
                                                       (In thousands)
Net change in deferred income tax
  liability from the preceding table                        $ 50,487
Deferred taxes associated with acquisitions                  (29,807)
Other                                                            334
Deferred income tax expense for the period                  $ 21,014


Total income tax expense differs from the amount computed by applying

the statutory federal income tax rate to income before taxes.  The

reasons for this difference are as follows:



Years ended December 31,          2001           2000           1999
                            Amount     %   Amount     %   Amount     %
                                       (Dollars in thousands)
Computed tax at federal
  statutory rate           $88,966  35.0  $63,237  35.0  $46,686  35.0
Increases (reductions)
  resulting from:
  State income taxes,
    net of federal
    income tax benefit      11,311   4.5    8,044   4.4    5,921   4.4
  Investment tax credit
    amortization              (731)  (.3)    (853)  (.5)    (888)  (.6)
  Depletion allowance       (1,820)  (.7)  (1,631)  (.9)  (1,300) (1.0)
  Other items                  615    .2      853    .5   (1,109)  (.8)
Total income tax expense   $98,341  38.7  $69,650  38.5  $49,310  37.0



NOTE 10

Business Segment Data

The company's reportable segments are those that are based on the

company's method of internal reporting, which generally segregates the

strategic business units due to differences in products, services and

regulation.



The company's operations are conducted through six business segments.

Substantially all of the company's operations are located within the

United States.  The electric segment generates, transmits and

distributes electricity and the natural gas distribution segment

distributes natural gas.  These operations also supply related

value-added products and services in the northern Great Plains.  The

utility services segment consists of a diversified infrastructure

company specializing in engineering, design and build capability for

electric, gas and telecommunication utility construction, as well as

industrial and commercial electrical, exterior lighting and traffic

signalization throughout most of the United States.  Utility services

provides related specialty equipment manufacturing sales and rental

services.  The pipeline and energy services segment provides natural

gas transportation, underground storage and gathering services through

regulated and nonregulated pipeline systems primarily in the Rocky

Mountain and northern Great Plains regions of the United States.

Energy-related marketing and management services as well as cable and

pipeline locating services also are provided.  The pipeline and energy

services segment includes investments in domestic and international

growth opportunities.  The natural gas and oil production segment is

engaged in natural gas and oil acquisition, exploration and production

activities primarily in the Rocky Mountain region of the United States

and in the Gulf of Mexico.  The construction materials and mining

segment mines aggregates and markets crushed stone, sand, gravel and

other related construction materials, including ready-mixed concrete,

cement and asphalt, as well as value-added products and services in the

north central and western United States, including Alaska and Hawaii.



In 2001, the company sold its coal operations to Westmoreland Coal

Company for $28.2 million in cash, including final settlement cost

adjustments.  The sale of the coal operations was effective April 30,

2001.  Included in the sale were active coal mines in North Dakota and

Montana, coal sales agreements, reserves and mining equipment, and

certain development rights at the former Gascoyne Mine site in North

Dakota.  The company retains ownership of coal reserves and leases at

its former Gascoyne Mine site.  Including final settlement cost

adjustments, the company recorded a gain of $10.3 million ($6.2 million

after-tax) included in other income - net from the sale in 2001.



On August 30, 2001, MDU Resources International, Inc. (MDU

International), a wholly owned subsidiary of the company, through an

indirect wholly owned Brazilian subsidiary, entered into a joint

venture agreement with a Brazilian firm under which the parties have

formed MPX Holdings, Ltda. (MPX) to develop electric generation and

transmission, steam generation, power equipment, coal mining and

construction materials projects in Brazil.  MDU International has a 49

percent interest in MPX.  MPX is currently developing, through a wholly

owned subsidiary, and has under construction a 200-megawatt natural gas-

fired power plant (Project) in the Brazilian state of Ceara.  The

Project is expected to enter commercial operation in the second quarter

of 2002.  MPX expects to enter into an agreement with Petrobras, the

state-controlled energy company, under which Petrobras would purchase

all of the capacity and market all of the Project's energy.  Petrobras

would also supply natural gas to the Project when energy is dispatched.

The Project has a total estimated construction cost of approximately

$96 million.  At December 31, 2001, MDU International's investment in

the Project was approximately $23.8 million.  In addition, the

company's subsidiaries had guaranteed Project obligations and loans for

approximately $17.3 million as of December 31, 2001.


Segment information follows the same accounting policies as described

in the Summary of Significant Accounting Policies.  Segment information

included in the accompanying Consolidated Balance Sheets as of

December 31 and included in the Consolidated Statements of Income for

the years then ended is as follows:


                                            2001         2000         1999
                                                   (In thousands)
External operating revenues:
  Electric                            $  168,837   $  161,621   $  154,869
  Natural gas distribution               255,389      233,051      157,692
  Utility services                       364,746      169,382       99,917
  Pipeline and energy services           479,108      579,207      334,188
  Natural gas and oil production         148,653       99,014       63,238
  Construction materials and mining      801,883      617,564      455,939
Total external operating revenues     $2,218,616   $1,859,839   $1,265,843

Intersegment operating revenues:
  Electric                            $      ---   $      ---   $      ---
  Natural gas distribution                   ---          ---          ---
  Utility services                             4          ---          ---
  Pipeline and energy services            52,006       57,641       49,344
  Natural gas and oil production          61,178       39,302       15,156
  Construction materials and mining(a)     5,016       13,832       13,966
  Intersegment eliminations             (113,188)     (96,943)     (64,500)
Total intersegment
  operating revenues(a)               $    5,016   $   13,832   $   13,966

Depreciation, depletion and
 amortization:
  Electric                            $   19,488   $   19,115   $   18,375
  Natural gas distribution                 9,337        8,399        7,348
  Utility services                         8,395        4,912        2,591
  Pipeline and energy services            14,341       15,301        8,248
  Natural gas and oil production          41,690       27,008       19,248
  Construction materials and mining       46,666       36,153       26,008
Total depreciation, depletion
  and amortization                    $  139,917   $  110,888   $   81,818

Interest expense:
  Electric                            $    8,531   $   10,007   $    9,692
  Natural gas distribution                 3,727        4,142        3,614
  Utility services                         3,807        2,492          812
  Pipeline and energy services             9,136       10,029        7,281
  Natural gas and oil production           1,359        5,160        3,405
  Construction materials and mining       19,339       16,415       11,202
  Intersegment eliminations                  ---         (212)         ---
Total interest expense                $   45,899   $   48,033   $   36,006

Income taxes:
  Electric                            $   10,511   $   10,048   $    8,678
  Natural gas distribution                 1,067        3,544        1,443
  Utility services                         9,131        6,027        4,323
  Pipeline and energy services            11,633        9,214       13,356
  Natural gas and oil production          40,486       23,906       10,032
  Construction materials and mining       25,513       16,911       11,478
Total income taxes                    $   98,341   $   69,650   $   49,310

Earnings on common stock:
  Electric                            $   18,717   $   17,733   $   15,973
  Natural gas distribution                   677        4,741        3,192
  Utility services                        12,910        8,607        6,505
  Pipeline and energy services            16,406       10,494       20,972
  Natural gas and oil production          63,178       38,574       16,207
  Construction materials and mining       43,199       30,113       20,459
Total earnings on common stock        $  155,087   $  110,262   $   83,308

Capital expenditures:
  Electric                            $   14,373   $   15,788   $   18,218
  Natural gas distribution                14,685       21,336        9,246
  Utility services                        70,232       42,633       16,052
  Pipeline and energy services            51,054       69,006       35,123
  Natural gas and oil production         118,719      173,441       64,294
  Construction materials and mining      170,585      218,716      105,098
  Net proceeds from sale or
   disposition of property               (51,641)     (11,000)     (16,660)
Total net capital expenditures        $  388,007   $  529,920   $  231,371

Identifiable assets:
  Electric(b)                         $  291,229   $  305,099   $  307,417
  Natural gas distribution(b)            182,705      192,854      131,294
  Utility services                       239,069      123,451       67,755
  Pipeline and energy services           346,879      362,592      302,587
  Natural gas and oil production         476,105      410,207      255,416
  Construction materials and mining    1,035,929      874,299      655,499
  Corporate assets(c)                     51,155       44,457       46,335
Total identifiable assets             $2,623,071   $2,312,959   $1,766,303

Property, plant and equipment:
  Electric (b)                        $  597,080   $  589,700   $  581,090
  Natural gas distribution (b)           238,566      227,742      185,797
  Utility services                        59,190       39,865       21,876
  Pipeline and energy services           410,049      369,834      308,409
  Natural gas and oil production         630,826      513,419      343,157
  Construction materials and mining      820,984      755,563      601,952
  Less accumulated depreciation,
   depletion and amortization            947,377      895,109      794,105
Net property, plant and equipment     $1,809,318   $1,601,014   $1,248,176

(a) In accordance with the provision of SFAS No. 71, intercompany coal
    sales are not eliminated.
(b) Includes, in the case of electric and natural gas distribution
    property, allocations of common utility property.
(c) Corporate assets consist of assets not directly assignable to a
    business segment (i.e., cash and cash equivalents, certain accounts
    receivable and other miscellaneous current and deferred assets).

Capital expenditures for 2001, 2000 and 1999, related to acquisitions,

in the preceding table include the following noncash transactions:

issuance of the company's equity securities of $57.4 million in 2001;

issuance of the company's equity securities and the conversion of a

note receivable to purchase consideration of $132.1 million in 2000;

and issuance of the company's equity securities of $77.5 million in

1999.



NOTE 11

Acquisitions

In 2001, the company acquired a number of businesses, none of which was

individually material, including construction materials and mining

businesses in Hawaii, Minnesota and Oregon; utility services businesses

based in Missouri and Oregon; and an energy services company

specializing in cable and pipeline locating and tracking systems.  The

total purchase consideration for these businesses, consisting of the

company's common stock and cash, was $170.1 million.



In 2000, the company acquired a number of businesses, none of which was

individually material, including construction materials and mining

businesses with operations in Alaska, California, Montana and Oregon; a

coalbed natural gas development operation based in Colorado with

related oil and gas leases and properties in Montana and Wyoming;

utility services businesses based in California, Colorado, Montana and

Ohio; a natural gas distribution business serving southeastern North

Dakota and western Minnesota; and an energy services company based in

Texas.  The total purchase consideration for these businesses,

consisting of the company's common stock, cash and the conversion of a

note receivable to purchase consideration, was $286.0 million.



On April 1, 2000, Fidelity Exploration & Production Company (Fidelity),

an indirect wholly owned subsidiary of the company, purchased

substantially all of the assets of Preston Reynolds & Co., Inc.

(Preston), a coalbed natural gas development operation, as previously

discussed.  Pursuant to the asset purchase and sale agreement, Preston

may, but is not obligated to purchase, acquire and own an undivided 25

percent working interest (Seller's Option Interest) in certain oil and

gas leases or properties acquired and/or generated by Fidelity.  The

Seller's Option Interest commences April 1, 2002 and terminates six

months thereafter and requires Preston to pay Fidelity 25 percent of

its capital investment, during the two year period subsequent to

April 1, 2000, in the oil and gas leases or properties.  Fidelity has

the right, but not the obligation, to purchase Seller's Option Interest

from Preston for an amount as specified in the agreement.



In 1999, the company acquired a number of businesses, none of which was

individually material, including construction materials and mining

companies with operations in California, Montana, Oregon and Wyoming;

and utility services companies based in Montana and Oregon.  The total

purchase consideration for these businesses, consisting of the

company's common stock and cash, was $81.9 million.



The above acquisitions were accounted for under the purchase method of

accounting and accordingly, the acquired assets and liabilities assumed

have been preliminarily recorded at their respective fair values as of

the date of acquisition.  Final fair market values are pending the

completion of the review of the relevant assets, liabilities and issues

identified as of the acquisition date on certain of the above

acquisitions made in 2001.  The results of operations of the acquired

businesses are included in the financial statements since the date of

each acquisition.  Pro forma financial amounts reflecting the effects

of the above acquisitions are not presented as such acquisitions were

not material to the company's financial position or results of

operations.



NOTE 12

Employee Benefit Plans

The company has noncontributory defined benefit pension plans and other

postretirement benefit plans.  Changes in benefit obligation and plan

assets for the years ended December 31 are as follows:

                                                                Other
                                           Pension          Postretirement
                                           Benefits            Benefits
                                        2001      2000      2001      2000
                                                  (In thousands)
Change in benefit obligation:
  Benefit obligation at
    beginning of year               $200,880  $180,997   $69,467   $65,939
  Service cost                         4,716     4,561     1,376     1,307
  Interest cost                       14,498    14,174     4,691     4,946
  Plan participants' contributions       ---       ---       866       677
  Amendments                          (1,342)    7,111       ---       ---
  Actuarial (gain) loss                8,128     9,535    (2,109)      928
  Divestiture*                       (10,017)      ---    (2,871)      ---
  Benefits paid                      (12,817)  (15,498)   (4,401)   (4,330)
Benefit obligation at
  end of year                        204,046   200,880    67,019    69,467

Change in plan assets:
  Fair value of plan assets at
    beginning of year                261,864   276,459    47,046    47,147
  Actual return on plan assets       (13,828)      875    (2,235)   (1,078)
  Employer contribution                  337        28     3,899     4,630
  Plan participants' contributions       ---       ---       866       677
  Divestiture*                       (10,889)      ---       ---       ---
  Benefits paid                      (12,817)  (15,498)   (4,401)   (4,330)
Fair value of plan assets at end
  of year                            224,667   261,864    45,175    47,046

  Funded status                       20,621    60,984   (21,844)  (22,421)
  Unrecognized actuarial gain        (26,170)  (76,417)  (10,799)  (15,228)
  Unrecognized prior service cost     10,278    16,271       ---       ---
  Unrecognized net transition
    obligation (asset)                (2,195)   (3,387)   23,665    28,532
Prepaid (accrued) benefit cost      $  2,534   $(2,549)  $(8,978)  $(9,117)

* See Note 10 for more information on the sale of the company's coal
  operations.


Weighted average assumptions for the company's pension and other

postretirement benefit plans as of December 31 are as follows:


                                                             Other
                                         Pension         Postretirement
                                         Benefits           Benefits
                                    2001      2000     2001      2000
Discount rate                       7.25%     7.50%    7.25%     7.50%
Expected return on plan assets      8.50%     8.50%    7.50%     7.50%
Rate of compensation increase       5.00%     5.00%    5.00%     5.00%


Health care rate assumptions for the company's other postretirement

benefit plans as of December 31 are as follows:


                                                      2001         2000
Health care trend rate                          6.00%-7.00%  6.00%-7.50%
Health care cost trend rate - ultimate          5.00%-6.00%  5.00%-6.00%
Year in which ultimate trend rate achieved       1999-2004    1999-2004


Components of net periodic benefit cost for the company's pension and

other postretirement benefit plans are as follows:


                                                            Other
                                 Pension                Postretirement
                                 Benefits                  Benefits
Years ended December 31,         2001     2000     1999    2001     2000    1999
                                             (In thousands)
Components of net periodic
 benefit cost:
  Service cost              $ 4,716  $ 4,561  $ 4,894  $ 1,376  $ 1,307  $1,451
  Interest cost              14,498   14,174   12,573    4,691    4,946   4,720
  Expected return on assets (20,672) (19,927) (17,489)  (3,619)  (3,267) (2,807)
  Amortization of prior
   service cost               1,247    1,047      842      ---      ---     ---
  Recognized net actuarial
   gain                      (2,687)  (2,907)    (995)    (930)    (799)   (200)
  Settlement (gain) loss       (884)    (700)     ---       15      ---     ---
  Amortization of net
   transition obligation
   (asset)                     (965)    (997)    (997)   2,227    2,378   2,377
Net periodic benefit cost
  (income)                   (4,747)  (4,749)  (1,172)   3,760    4,565   5,541
Less amount capitalized        (391)    (397)     (87)     329      369     463
Net periodic benefit
  expense (income)          $(4,356) $(4,352) $(1,085) $ 3,431  $ 4,196  $5,078


The company's other postretirement benefit plans include health care

and life insurance benefits.  The plans underlying these benefits may

require contributions by the employee depending on such employee's age

and years of service at retirement or the date of retirement.  The

accounting for the health care plans anticipates future cost-sharing

changes that are consistent with the company's expressed intent to

generally increase retiree contributions each year by the excess of the

expected health care cost trend rate over 6 percent.



Assumed health care cost trend rates may have a significant effect on

the amounts reported for the health care plans.  A one percentage point

change in the assumed health care cost trend rates would have the

following effects at December 31, 2001:


                                       1 Percentage      1 Percentage
                                      Point Increase    Point Decrease
                                             (In thousands)
Effect on total of service
  and interest cost components             $   260            $  (229)
Effect on postretirement benefit
  obligation                               $ 3,326            $(2,906)


In addition to company-sponsored plans, certain employees are covered

under multi-employer defined benefit plans administered by a union.

Amounts contributed to the multi-employer plans were $19.9 million,

$10.6 million and $6.8 million in 2001, 2000 and 1999, respectively.



The company has an unfunded, nonqualified benefit plan for executive

officers and certain key management employees that provides for defined

benefit payments upon the employee's retirement or to their

beneficiaries upon death for a 15-year period.  Investments consist of

life insurance carried on plan participants, which is payable to the

company upon the employee's death.  The cost of these benefits was

$4.3 million, $3.5 million and $3.3 million in 2001, 2000 and 1999,

respectively.



The company sponsors various defined contribution plans for eligible

employees.  Costs incurred by the company under these plans were

$7.2 million in 2001, $6.1 million in 2000 and $4.4 million in 1999.

The costs incurred in each year reflect additional participants as a

result of business acquisitions.



NOTE 13

Jointly Owned Facilities

The consolidated financial statements include the company's 22.7

percent and 25.0 percent ownership interests in the assets, liabilities

and expenses of the Big Stone Station and the Coyote Station,

respectively.  Each owner of the Big Stone and Coyote stations is

responsible for financing its investment in the jointly owned

facilities.



The company's share of the Big Stone Station and Coyote Station

operating expenses is reflected in the appropriate categories of

operating expenses in the Consolidated Statements of Income.



At December 31, the company's share of the cost of utility plant in

service and related accumulated depreciation for the stations was as

follows:

                                                     2001        2000
                                                     (In thousands)
Big Stone Station:
  Utility plant in service                       $ 50,053    $ 50,029
  Less accumulated depreciation                    32,956      31,381
                                                 $ 17,097    $ 18,648
Coyote Station:
  Utility plant in service                       $122,436    $122,111
  Less accumulated depreciation                    67,414      63,741
                                                 $ 55,022    $ 58,370


NOTE 14

Regulatory Matters and Revenues Subject To Refund

In December 1999, Williston Basin Interstate Pipeline Company

(Williston Basin), an indirect wholly owned subsidiary of the company,

filed a general natural gas rate change application with the FERC.

Williston Basin began collecting such rates effective June 1, 2000,

subject to refund.  On May 9, 2001, the Administrative Law Judge issued

an Initial Decision on Williston Basin's natural gas rate change

application, which matter is currently pending before and subject to

revision by the FERC.



Reserves have been provided for a portion of the revenues that have

been collected subject to refund with respect to the pending regulatory

proceeding.  Williston Basin, in the fourth quarter of 2000, determined

that reserves it had previously established for certain regulatory

proceedings, prior to the proceeding filed in 1999, exceeded its

expected refund obligation and, accordingly, reversed reserves and

recognized in income $6.7 million after-tax.  Williston Basin, in the

second quarter of 1999, determined that reserves it had previously

established in relation to a 1992 general natural gas rate change

application and the 1995 general rate increase application exceeded its

expected refund obligation and, accordingly, reversed reserves and

recognized in income $4.4 million after-tax.  Williston Basin believes

that its remaining reserves are adequate based on its assessment of the

ultimate outcome of the application filed in December 1999.



NOTE 15

Commitments and Contingencies

Litigation


In March 1997, 11 natural gas producers filed suit in North Dakota

Southwest Judicial District Court (North Dakota District Court) against

Williston Basin and the company.  The natural gas producers had

processing agreements with Koch Hydrocarbon Company (Koch).  Williston

Basin and the company had natural gas purchase contracts with Koch.

The natural gas producers alleged they were entitled to damages for the

breach of Williston Basin's and the company's contracts with Koch

although no specific damages were stated.  A similar suit was filed by

Apache Corporation (Apache) and Snyder Oil Corporation (Snyder) in

North Dakota Northwest Judicial District Court in December 1993.  The

North Dakota Supreme Court in December 1999 affirmed the North Dakota

Northwest Judicial District Court decision dismissing Apache's and

Snyder's claims against Williston Basin and the company.  Based in part

upon the decision of the North Dakota Supreme Court affirming the

dismissal of the claims brought by Apache and Snyder, Williston Basin

and the company filed motions for summary judgment to dismiss the

claims of the 11 natural gas producers.  The motions for summary

judgment were granted by the North Dakota District Court in July 2000.

On March 5, 2001, the North Dakota District Court entered a final

judgment on the July 2000 order granting the motions for summary

judgment.  On May 4, 2001, the 11 natural gas producers appealed the

North Dakota District Court's decision by filing a Notice of Appeal

with the North Dakota Supreme Court.  Oral argument was held before the

North Dakota Supreme Court on December 12, 2001.  Williston Basin and

the company are awaiting a decision from the North Dakota Supreme

Court.



In July 1996, Jack J. Grynberg (Grynberg) filed suit in United States

District Court for the District of Columbia (U.S. District Court)

against Williston Basin and over 70 other natural gas pipeline

companies.  Grynberg, acting on behalf of the United States under the

Federal False Claims Act, alleged improper measurement of the heating

content or volume of natural gas purchased by the defendants resulting

in the underpayment of royalties to the United States.  In March 1997,

the U.S. District Court dismissed the suit without prejudice and the

dismissal was affirmed by the United States Court of Appeals for the

D.C. Circuit in October 1998.  In June 1997, Grynberg filed a similar

Federal False Claims Act suit against Williston Basin and Montana-

Dakota Utilities Co. (Montana-Dakota) and filed over 70 other separate

similar suits against natural gas transmission companies and producers,

gatherers, and processors of natural gas.  In April 1999, the United

States Department of Justice decided not to intervene in these cases.

In response to a motion filed by Grynberg, the Judicial Panel on

Multidistrict Litigation consolidated all of these cases in the Federal

District Court of Wyoming (Federal District Court).  Oral argument on

motions to dismiss was held before the Federal District Court in

March 2000.  On May 18, 2001, the Federal District Court denied

Williston Basin's and Montana-Dakota's motion to dismiss.  The matter

is currently pending.



The Quinque Operating Company (Quinque), on behalf of itself and

subclasses of gas producers, royalty owners and state taxing

authorities, instituted a legal proceeding in State District Court for

Stevens County, Kansas, (State District Court) against over 200 natural

gas transmission companies and producers, gatherers, and processors of

natural gas, including Williston Basin and Montana-Dakota.  The

complaint, which was served on Williston Basin and Montana-Dakota in

September 1999, contains allegations of improper measurement of the

heating content and volume of all natural gas measured by the

defendants other than natural gas produced from federal lands.  In

response to a motion filed by the defendants in this suit, the Judicial

Panel on Multidistrict Litigation transferred the suit to the Federal

District Court for inclusion in the pretrial proceedings of the

Grynberg suit.  Upon motion of plaintiffs, the case has been remanded

to State District Court.  On September 12, 2001, the defendants in this

suit filed a motion to dismiss with the State District Court.  The

matter is currently pending.



Williston Basin and Montana-Dakota believe the claims of Grynberg and

Quinque are without merit and intend to vigorously contest these suits.



The company is also involved in other legal actions in the ordinary

course of its business.  Although the outcomes of any such legal

actions cannot be predicted, management believes that there is no

pending legal proceeding against or involving the company, except those

discussed above, for which the outcome is likely to have a material

adverse effect upon the company's financial position or results of

operations.



Environmental matters

In December 2000, Morse Bros., Inc. (MBI), an indirect wholly owned

subsidiary of the company, was named by the United States Environmental

Protection Agency (EPA) as a Potentially Responsible Party in

connection with the cleanup of a commercial property site, now owned by

MBI, and part of the Portland, Oregon, Harbor Superfund Site.  Sixty-

eight other parties were also named in this administrative action.  The

EPA wants responsible parties to share in the cleanup of sediment

contamination in the Willamette River.  Based upon a review of the

Portland Harbor sediment contamination evaluation by the Oregon State

Department of Environmental Quality and other information available,

MBI does not believe it is a Responsible Party.  In addition, MBI

intends to seek indemnity for any and all liabilities incurred in

relation to the above matters from Georgia-Pacific West, Inc., the

seller of the commercial property site to MBI, pursuant to the terms of

their sale agreement.


Operating leases

The company leases certain equipment, facilities and land under

operating lease agreements.  The amounts of annual minimum lease

payments due under these leases as of December 31, 2001, are

$17.4 million in 2002, $14.3 million in 2003, $11.0 million in 2004,

$8.3 million in 2005, $6.3 million in 2006 and $25.1 million

thereafter.  Rent expense related to operating leases was approximately

$31.5 million, $23.7 million and $15.4 million for the years ended

December 31, 2001, 2000 and 1999, respectively.



Purchase commitments

The company has entered into various commitments, largely purchased-

power, coal and natural gas supply, and natural gas transportation

contracts.  These commitments range from one to 17 years.  The

commitments under these contracts as of December 31, 2001, are

$108.8 million in 2002, $53.1 million in 2003, $46.9 million in 2004,

$39.2 million in 2005, $33.2 million in 2006 and $126.5 million

thereafter.  These commitments are not reflected in the company's

consolidated financial statements.



Guarantees

The company has certain financial guarantees largely consisting of

guarantees on obligations and loans on the natural gas-fired power

plant project in the Brazilian state of Ceara.  For more information on

the natural gas-fired power plant project see Note 10.  These

guarantees, as of December 31, 2001, are approximately $20.6 million

for 2002.  These guarantees are not reflected in the consolidated

financial statements.



NOTE 16

Quarterly Data (Unaudited)

The following unaudited information shows selected items by quarter for

the years 2001 and 2000:


                                   First    Second     Third    Fourth
                                 Quarter   Quarter   Quarter   Quarter
                               (In thousands, except per share amounts)
2001
Operating revenues              $641,248  $546,418  $551,680  $484,286
Operating expenses               577,727   476,071   458,441   438,125
Operating income                  63,521    70,347    93,239    46,161
Net income                        32,687    43,417    50,746    28,999
Earnings per common share:
  Basic                              .50       .64       .75       .42
  Diluted                            .49       .63       .74       .42
Weighted average common shares
  outstanding:
  Basic                           65,405    67,264    67,650    68,729
  Diluted                         65,979    68,376    68,127    69,126


2000
Operating revenues              $371,989  $362,979  $530,834  $607,869
Operating expenses               342,559   321,900   454,811   537,414
Operating income                  29,430    41,079    76,023    70,455
Net income                        13,364    21,126    39,992    36,546
Earnings per common share:
  Basic                              .23       .35       .63       .57
  Diluted                            .23       .35       .63       .56
Weighted average common shares
  outstanding:
  Basic                           57,051    59,987    62,975    64,289
  Diluted                         57,188    60,212    63,345    64,817


Certain company operations are highly seasonal and revenues from and

certain expenses for such operations may fluctuate significantly among

quarterly periods.  Accordingly, quarterly financial information may

not be indicative of results for a full year.



NOTE 17

Natural Gas and Oil Activities (Unaudited)

Fidelity is involved in the acquisition, exploration, development and

production of natural gas and oil resources.  Fidelity's activities

include the acquisition of producing properties with potential

development opportunities, exploratory drilling and the operation and

development of natural gas production properties.  Fidelity shares

revenues and expenses from the development of specified properties

located primarily in the Rocky Mountain region of the United States and

in the Gulf of Mexico in proportion to its interests.


Fidelity owns in fee or holds natural gas leases for the properties it

operates in Colorado, Montana, North Dakota and Wyoming.  These rights

are in the Bonny Field located in eastern Colorado, the Cedar Creek

Anticline in southeastern Montana and southwestern North Dakota, the

Bowdoin area located in north-central Montana and in the Powder River

Basin of Wyoming and Montana.



The information that follows includes the company's proportionate share

of all its natural gas and oil interests held by Fidelity.



The following table sets forth capitalized costs and accumulated

depreciation, depletion and amortization related to natural gas and oil

producing activities at December 31:


                                        2001        2000        1999
                                              (In thousands)
Subject to amortization             $506,155    $416,881    $319,448
Not subject to amortization          122,354      94,856      23,464
Total capitalized costs              628,509     511,737     342,912
Less accumulated depreciation,
  depletion and amortization         195,469     155,198     129,211
Net capitalized costs               $433,040    $356,539    $213,701


Capital expenditures, including those not subject to amortization,

related to natural gas and oil producing activities are as follows:



Years ended December 31,                2001        2000        1999
                                              (In thousands)
Acquisitions                        $  1,695    $ 68,858    $ 30,842
Exploration                           13,938      34,839      11,010
Development                          102,670      69,051      21,822
Total capital expenditures          $118,303    $172,748    $ 63,674


The following summary reflects income resulting from the company's

operations of natural gas and oil producing activities, excluding

corporate overhead and financing costs:


Years ended December 31,                2001        2000        1999
                                              (In thousands)
Revenues                            $203,727    $128,217    $ 75,327
Production costs                      47,045      33,919      25,402
Depreciation, depletion and
  amortization                        41,223      26,739      19,136
Pretax income                        115,459      67,559      30,789
Income tax expense                    45,245      25,835      11,815
Results of operations for
  producing activities              $ 70,214    $ 41,724    $ 18,974


The following table summarizes the company's estimated quantities of

proved natural gas and oil reserves at December 31, 2001, 2000 and

1999, and reconciles the changes between these dates.  Estimates of

economically recoverable natural gas and oil reserves and future net

revenues therefrom are based upon a number of variable factors and

assumptions.  For these reasons, estimates of economically recoverable

reserves and future net revenues may vary from actual results.

                               2001             2000            1999
                         Natural         Natural          Natural
                             Gas     Oil     Gas      Oil     Gas     Oil
                               (In thousands of Mcf/barrels)
Proved developed and
  undeveloped reserves:
  Balance at beginning
    of year              309,800  15,100 268,900   14,700 243,600  11,500
  Production             (40,600) (2,000)(29,200)  (1,900)(24,700) (1,800)
  Extensions and
    discoveries           66,400   2,000  51,300    1,600  21,800     800
  Purchases of proved
    reserves               1,000     100  23,200      100  38,200     700
  Sales of reserves
    in place                 ---     ---     ---     (100) (9,300)   (400)
  Revisions to previous
    estimates due to
    improved secondary
    recovery techniques
    and/or changed
    economic conditions  (12,500)  2,300  (4,400)     700    (700)  3,900
Balance at end
  of year                324,100  17,500 309,800   15,100 268,900  14,700


Proved developed reserves:
  January 1, 1999       193,000   10,700
  December 31, 1999     213,400   13,300
  December 31, 2000     263,400   14,200
  December 31, 2001     291,300   17,100


All of the company's interests in natural gas and oil reserves are

located in the United States and in the Gulf of Mexico.


The standardized measure of the company's estimated discounted future

net cash flows of total proved reserves associated with its various

natural gas and oil interests at December 31 is as follows:


                                         2001        2000        1999
                                              (In thousands)
Future net cash flows before
  income taxes                       $548,000  $2,349,500    $492,000
Future income tax expense             112,000     827,000     131,500
Future net cash flows                 436,000   1,522,500     360,500
10% annual discount for estimated
  timing of cash flows                174,000     601,200     131,400
Discounted future net cash flows
  relating to proved natural gas
  and oil reserves                   $262,000  $  921,300    $229,100


The following are the sources of change in the standardized measure

of discounted future net cash flows by year:


                                         2001        2000         1999
                                             (In thousands)
Beginning of year                 $   921,300    $229,100     $125,100
Net revenues from production         (153,500)    (94,300)     (49,900)
Change in net realization          (1,119,700)    861,700      123,100
Extensions, discoveries and
  improved recovery, net of
  future production-related costs      64,200     288,700       33,500
Purchases of proved reserves            2,600      93,200       57,700
Sales of reserves in place                ---      (1,500)     (14,700)
Changes in estimated future
  development costs, net of those
  incurred during the year             (3,300)      3,400       (9,800)
Accretion of discount                 126,900      31,200       16,700
Net change in income taxes            436,500    (412,300)     (59,800)
Revisions of previous quantity
  estimates                           (11,700)    (79,200)       7,400
Other                                  (1,300)      1,300         (200)
Net change                           (659,300)    692,200      104,000
End of year                       $   262,000    $921,300     $229,100


The estimated discounted future cash inflows from estimated future

production of proved reserves were computed using year-end natural gas

prices and oil prices.  Future development and production costs

attributable to proved reserves were computed by applying year-end

costs to be incurred in producing and further developing the proved

reserves.  Future income tax expenses were computed by applying

statutory tax rates (adjusted for permanent differences and tax

credits) to estimated net future pretax cash flows.


The standardized measure of discounted future net cash flows does not

purport to represent the fair market value of natural gas and oil

properties.  There are significant uncertainties inherent in estimating

quantities of proved reserves and in projecting rates of production and

the timing and amount of future costs.  In addition, future realization

of natural gas and oil prices over the remaining reserve lives may vary

significantly from current prices.



NOTE 18

Subsequent Event

In January 2002, Fidelity Oil Co. (FOC), one of the company's natural

gas and oil production subsidiaries, entered into a compromise

agreement with the former operator of certain of FOC's oil production

properties in southeastern Montana.  The compromise agreement resolved

litigation involving the interpretation and application of contractual

provisions regarding net proceeds interests paid by the former operator

to FOC for a number of years prior to 1998.  The terms of the

compromise agreement are confidential.  As a result of the compromise

agreement, the natural gas and oil production segment will reflect a

nonrecurring gain in its financial results for the first quarter of

2002 of approximately $16.6 million after-tax.  As part of the

settlement, FOC gave the former operator a full and complete release,

and FOC is not asserting any such claim against the former operator for

periods after 1997.



Report of Independent Public Accountants


To MDU Resources Group, Inc.:
We have audited the accompanying consolidated balance sheets of MDU
Resources Group, Inc. (a Delaware corporation) and Subsidiaries as of
December 31, 2001 and 2000, and the related consolidated statements of
income, common stockholders' equity and cash flows for each of the
three years in the period ended December 31, 2001.  These financial
statements are the responsibility of the company's management.  Our
responsibility is to express an opinion on these financial statements
based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States.  Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  An audit
includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements.  An audit also includes
assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall financial statement
presentation.  We believe that our audits provide a reasonable basis
for our opinion.

In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of MDU
Resources Group, Inc. and Subsidiaries as of December 31, 2001 and
2000, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States.

As explained in Note 1 to the consolidated financial statements,
effective January 1, 2001, the company changed its method of accounting
for derivative instruments due to the adoption of a new accounting
pronouncement.



                                         /s/ ARTHUR ANDERSEN LLP
                                         ARTHUR ANDERSEN LLP

Minneapolis, Minnesota
January 23, 2002

<TABLE>

                                                             OPERATING STATISTICS
                                                           MDU RESOURCES GROUP, INC.
<CAPTION>
                                                2001         2000         1999         1998*        1997         1996         1991
<S>                                       <C>          <C>          <C>          <C>          <C>          <C>          <C>
Selected Financial Data
Operating revenues (000's):
 Electric                                 $  168,837   $  161,621   $  154,869   $  147,221   $  141,590   $  138,761   $  128,708
 Natural gas distribution                    255,389      233,051      157,692      154,147      157,005      155,012      138,634
 Utility services                            364,750      169,382       99,917       64,232       22,761          ---          ---
 Pipeline and energy services                531,114      636,848      383,532      180,732       87,018       71,580      108,397
 Natural gas and oil production              209,831      138,316       78,394       61,842       77,916       75,350       41,583
 Construction materials and mining           806,899      631,396      469,905      346,451      174,147      132,222       41,201
 Intersegment eliminations                  (113,188)     (96,943)     (64,500)     (57,998)     (52,763)     (58,224)     (80,810)
                                          $2,223,632   $1,873,671   $1,279,809   $  896,627   $  607,674   $  514,701   $  377,713
Operating income (000's):
 Electric                                 $   38,731   $   38,743   $   35,727   $   32,167   $   31,307   $   29,476   $   34,647
 Natural gas distribution                      3,576        9,530        6,688        8,028       10,410       11,504        8,518
 Utility services                             25,199       16,606       11,518        5,932        1,782          ---          ---
 Pipeline and energy services                 30,368       28,782       40,627       33,651       25,822       27,697       15,516
 Natural gas and oil production              103,943       66,510       26,845      (50,444)      27,638       26,786       16,940
 Construction materials and mining            71,451       56,816       38,346       41,609       14,602       16,062        9,682
                                          $  273,268   $  216,987   $  159,751   $   70,943   $  111,561   $  111,525   $   85,303
Earnings on common stock (000's):
 Electric                                 $   18,717   $   17,733   $   15,973   $   13,908   $   12,441   $   11,436   $   15,292
 Natural gas distribution                        677        4,741        3,192        3,501        4,514        4,892        3,645
 Utility services                             12,910        8,607        6,505        3,272          947          ---          ---
 Pipeline and energy services                 16,406       10,494       20,972       18,651        9,955        1,649       (1,950)
 Natural gas and oil production               63,178       38,574       16,207      (30,501)      15,867       15,185       10,409
 Construction materials and mining            43,199       30,113       20,459       24,499       10,111       11,521        9,809
                                          $  155,087   $  110,262   $   83,308   $   33,330   $   53,835   $   44,683   $   37,205
Earnings per common share -- diluted      $     2.29   $     1.80   $     1.52   $      .66   $     1.24   $     1.04   $      .87

Common Stock Statistics
Weighted average common shares
 outstanding -- diluted (000's)               67,869       61,390       54,870       50,837       43,478       42,824       42,715
Dividends per common share                $      .90   $      .86   $      .82   $    .7834   $    .7534   $    .7333   $    .6378
Book value per common share               $    15.90   $    13.55   $    11.74   $    10.39   $     8.84   $     8.21   $     6.95
Market price per common share (year-end)  $    28.15   $    32.50   $    20.00   $    26.31   $    21.08   $    15.33   $    10.95
Market price ratios:
 Dividend payout                                 39%          48%          54%         119%          61%          70%          73%
 Yield                                          3.3%         2.7%         4.2%         3.0%         3.6%         4.8%         5.8%
 Price/earnings ratio                          12.3x        18.1x        13.2x        39.9x        17.0x        14.6x        12.6x
 Market value as a percent of book value      177.0%       239.9%       170.4%       253.2%       238.5%       186.8%       157.7%

Profitability Indicators
Return on average common equity                15.3%        14.3%        13.9%         6.5%        14.6%        13.0%        12.7%
Return on average invested capital             10.1%         9.5%         9.6%         5.5%        10.3%         9.5%         9.6%
Interest coverage                               8.5x         8.3x         7.1x         6.1x         6.0x         5.4x         3.8x**
Fixed charges coverage, including
 preferred dividends                            5.3x         4.1x         4.3x         2.5x         3.4x         2.7x         2.4x

General
Total assets (000's)                      $2,623,071   $2,312,959   $1,766,303   $1,452,775   $1,113,892   $1,089,173   $  964,691
Net long-term debt (000's)                $  783,709   $  728,166   $  563,545   $  413,264   $  298,561   $  280,666   $  220,623
Redeemable preferred stock (000's)        $    1,400   $    1,500   $    1,600   $    1,700   $    1,800   $    1,900   $    2,400
Capitalization ratios:
 Common equity                                   58%          54%          54%          56%          55%          54%          56%
 Preferred stocks                                 1            1            1            2            2            3            3
 Long-term debt                                  41           45           45           42           43           43           41
                                                100%         100%         100%         100%         100%         100%         100%
<FN>
*  Reflects $39.9 million or 78 cents per common share in noncash after-tax write-downs of natural gas and oil properties.
** Calculation reflects the provisions of the company's restatement of its indenture of mortgage effective April 1992.
</FN>
NOTE: Common stock share amounts reflect the company's three-for-two common stock splits effected in October 1995 and July 1998.
</TABLE>



<TABLE>
<CAPTION>
                                                  2001         2000         1999         1998         1997         1996         1991
<S>                                          <C>          <C>          <C>          <C>          <C>          <C>          <C>
Electric
Sales to ultimate consumers (thousand kWh)   2,177,886    2,161,280    2,075,446    2,053,862    2,041,191    2,067,926    1,877,634
Sales for resale (thousand kWh)                898,178      930,318      943,520      586,540      361,954      374,535      331,314
Electric system generating and firm purchase
 capability -- kW (Interconnected system)      500,820      500,420      492,800      489,100      487,500      481,800      454,400
Demand peak -- kW (Interconnected system)      453,000      432,300      420,550      402,500      404,600      393,300      387,100
Electricity produced (thousand kWh)          2,469,573    2,331,188    2,350,769    2,103,199    1,826,770    1,829,669    1,736,187
Electricity purchased (thousand kWh)           792,641      948,700      860,508      730,949      769,679      809,261      611,884
Average cost of fuel and purchased
  power per kWh                                  $.018        $.016        $.016        $.017        $.018        $.017        $.016

Natural Gas Distribution
Sales (Mdk)                                     36,479       36,595       30,931       32,024       34,320       38,283       30,074
Transportation (Mdk)                            14,338       14,314       11,551       10,324       10,067        9,423       12,261
Weighted average degree days --
 % of previous year's actual                       95%         113%          95%          94%          85%         114%         101%

Pipeline and Energy Services
Pipeline:
 Sales for resale (Mdk)                            ---          ---          ---          ---          ---          ---       19,572
 Transportation (Mdk)                           97,199       86,787       78,061       88,974       85,464       82,169       53,930
 Gathering (Mdk)                                61,136       41,717       19,799        9,093        9,550        8,983        6,116
Energy services:
 Natural gas volumes (Mdk)                      82,682      149,823      131,687       58,495       14,971        4,670          991

Natural Gas and Oil Production
Production:
 Natural gas (MMcf)                             40,591       29,222       24,652       20,699       20,407       20,391        6,557
 Oil (000's of barrels)                          2,042        1,882        1,758        1,912        2,088        2,149        1,491
Average realized prices:
 Natural gas (per Mcf)                          $ 3.78       $ 2.90       $ 1.94       $ 1.81       $ 2.02       $ 1.79       $ 1.74
 Oil (per barrel)                               $24.59       $23.06       $15.34       $12.71       $17.50       $17.91       $19.90
Net recoverable reserves:
 Natural gas (MMcf)                            324,100      309,800      268,900      243,600      184,900      200,200       27,500
 Oil (000's of barrels)                         17,500       15,100       14,700       11,500       14,900       16,100       11,600

Construction Materials and Mining
Construction materials (000's):
 Aggregates (tons sold)                         27,565       18,315       13,981       11,054        5,113        3,374          ---
 Asphalt (tons sold)                             6,228        3,310        2,993        1,790          758          694          ---
 Ready-mixed concrete (cubic yards sold)         2,542        1,696        1,186        1,021          516          340          ---
 Recoverable aggregate reserves (tons)       1,065,330      894,500      740,030      654,670      169,375      119,800          ---
Coal (000's):
 Sales (tons)                                    1,171*       3,111        3,236        3,113        2,375        2,899        4,731
 Recoverable reserves (tons)                    56,012*     145,643      182,761      190,152      226,560      228,900      256,700
<FN>
* Coal operations were sold effective April 30, 2001.
</FN>
</TABLE>



Change in Accountants

On February 14, 2002, upon the recommendation of the Audit
Committee of the Board of Directors, the Board of Directors of
the company approved the dismissal of Arthur Andersen LLP (Arthur
Andersen) as the company's independent auditors following the
2001 audit.  The company has not selected independent auditors
for the 2002 fiscal year, but is currently in the process of
reviewing new auditor candidates and expects to make a selection
in the near future.

In connection with the audits for the two most recent fiscal
years and through February 20, 2002, there have been no
disagreements with Arthur Andersen on any matter of accounting
principles or practices, financial statement disclosure, or
auditing scope or procedure, which disagreements, if not resolved
to the satisfaction of Arthur Andersen, would have caused Arthur
Andersen to make reference thereto in its report on the financial
statements of the company for such time periods.  Also, during
those time periods, there have been no "reportable events," as
such term is used in Item 304 (a)(1)(v) of Regulation S-K.

Arthur Andersen's reports on the financial statements of the
company for the last two years neither contained an adverse
opinion or disclaimer of opinion, nor were they qualified or
modified as to uncertainty, audit scope, or accounting
principles.

We have provided Arthur Andersen a copy of the company's Form 8-K
prior to its filing with the Securities and Exchange Commission
(Commission).  Arthur Andersen has provided us with a letter,
addressed to the Commission, which is filed as an Exhibit to the
company's Form 8-K, as filed with the Commission on February 20,
2002.


To MDU Resources Group, Inc.:

We have audited in accordance with auditing standards
generally accepted in the United States, the financial
statements included in MDU Resources Group, Inc.'s annual
report to stockholders incorporated by reference in this Form
10-K, and have issued our report thereon dated January 23,
2002.  Our audit was made for the purpose of forming an
opinion on those statements taken as a whole.  Schedule II is
the responsibility of the company's management and is
presented for purposes of complying with the Securities and
Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the
auditing procedures applied in the audit of the basic
financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth
therein in relation to the basic financial statements taken as
a whole.


                                     /s/ ARTHUR ANDERSEN LLP
                                     ARTHUR ANDERSEN LLP


  Minneapolis, Minnesota,
     January 23, 2002



                           MDU RESOURCES GROUP, INC.
         SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
                   YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999


                                        Additions
                     Balance at  Charged to                              Balance
                     beginning   costs and                               at end
Description           of year     expenses   Other(a)(b)  Deductions(c)  of year
- -----------          ----------  ----------  -----------  -------------  -------
                                       (In thousands)
Allowance for
 doubtful accounts:
    2001               $4,063      $3,896      $2,003        $4,189       $5,773
    2000               $2,111      $4,252      $1,085        $3,385       $4,063
    1999               $1,685      $1,359      $  395        $1,328       $2,111


(a) Allowance for doubtful accounts for companies acquired
(b) Recoveries
(c) Uncollectible accounts written off


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-21
<SEQUENCE>9
<FILENAME>sublist21.txt
<DESCRIPTION>SUBSIDIARIES OF MDU RESOURCES GROUP, INC.
<TEXT>

                   MDU RESOURCES GROUP, INC.
                      List of Subsidiaries
                  (Effective December 31, 2001)

                                          State or Other
                                           Jurisdiction
                                             in Which
                                           Incorporated
                                          --------------
Alaska Basic Industries, Inc.                Alaska
Anchorage Sand and Gravel Company, Inc.      Alaska
Baldwin Contracting Company, Inc.            California
Bauerly Brothers, Inc.                       Minnesota
Bell Electrical Contractors, Inc.            Missouri
Capital Electric Construction Company, Inc.  Kansas
Capital Electric Line Builders, Inc.         Kansas
Centennial Energy Holdings, Inc.             Delaware
Centennial Holdings Capital Corp.            Delaware
Centennial Power, Inc.                       Delaware
Concrete, Inc.                               California
Connolly-Pacific Co.                         California
DSS Company                                  California
Fidelity E & P International                 Cayman Islands
Fidelity Exploration & Production Company    Delaware
Fidelity Oil Co.                             Delaware
Frebco, Inc.                                 Ohio
FutureSource Capital Corp.                   Delaware
Hamlin Electric Company                      Colorado
Hap Taylor & Sons, Inc.                      Oregon
Harp Engineering, Inc.                       Montana
ILB Hawaii, Inc.                             Hawaii
Innovative Gas Services, Incorporated        Kentucky
Innovatum, Inc.                              Texas
International Line Builders, Inc.            Delaware
InterSource Insurance Company                Vermont
JTL Group, Inc. - Montana                    Montana
JTL Group, Inc. - Wyoming                    Wyoming
KRC Aggregate, Inc.                          Delaware
KRC Holdings, Inc.                           Delaware
Knife River Corporation                      Delaware
Knife River Dakota, Inc.                     Delaware
Knife River Hawaii, Inc.                     Delaware
Knife River Marine, Inc.                     Delaware
LTM, Incorporated                            Oregon
Loy Clark Pipeline Co.                       Oregon
MDU Resources International, Inc.            Delaware
Marcon Energy Corporation                    Kentucky
Medford Ready Mix, Inc.                      Delaware
Morse Bros., Inc.                            Oregon
Newco, Inc.                                  Ohio
Oregon Electric Construction, Inc.           Oregon
Pouk & Steinle, Inc.                         California
Prairielands Energy Marketing, Inc.          Delaware
Rocky Mountain Contractors, Inc.             Montana
Rogue Aggregates, Inc.                       Oregon
Utility Services, Inc.                       Delaware
WBI Canadian Pipeline, Ltd.                  Canada
WBI Energy Services, Inc.                    Delaware
WBI Holdings, Inc.                           Delaware
WBI Pipeline & Storage Group, Inc.           Delaware
WHC, Ltd.                                    Hawaii
Wagner-Smith Company, The                    Ohio
Wagner-Smith Equipment Co.                   Delaware
Wagner-Smith Pumps & Systems, Inc.           Ohio
Williston Basin Interstate Pipeline Company  Delaware

Bitter Creek Pipelines, LLC                  Colorado LLC
Central Oregon Redi-Mix, L.L.C.              Oregon LLC
Netricity LLC                                Alaska LLC
New Avoca Gas Storage LLC                    Texas LLC
Wagon Box Partners, LLC                      Colorado LLC
Hawaiian Cement                              Hawaii Partnership

MDU Resources Luxembourg I LLC S.a.r.l.      Luxembourg
MDU Resources Luxembourg II LLC S.a.r.l.     Luxembourg
MDU Brasil Ltda.                             Brazil


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23
<SEQUENCE>10
<FILENAME>consent-exh23.txt
<DESCRIPTION>CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
<TEXT>




            CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS


As independent public accountants, we hereby consent to the
incorporation by reference in this Form 10-K of our report dated
January 23, 2002 included in the MDU Resources Group, Inc. Annual
Report to Stockholders for 2001 and the inclusion of our report
dated January 23, 2002 on schedules included in this Form 10-K.
It should be noted that we have not audited any financial
statements of MDU Resources Group, Inc. subsequent to
December 31, 2001 or performed any audit procedures subsequent
to the date of our report.

As independent public accountants, we also hereby consent to the
incorporation of our reports included in or incorporated by
reference in this Form 10-K into the Company's previously
filed Registration Statements on Form S-3, No. 333-06127,
No. 333-49472 and No. 333-49484, and on Form S-8, No. 33-54486,
No. 333-06103, No. 333-06105, No. 333-27879, No. 333-27877,
No. 333-72595, No. 333-33186, No. 333-33184, No. 333-70622
and No. 333-62900.




                              /s/ ARTHUR ANDERSEN LLP
                              ARTHUR ANDERSEN LLP


Minneapolis, Minnesota
  March 1, 2002

</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>
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