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.
Fair
2002 2003 2004 2005 2006 Thereafter Total Value
(Dollars in millions)
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% -
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