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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, 2002
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______________ to ____________
Commission file number 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)
Delaware 41-0423660
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
Schuchart Building
918 East Divide Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)
(701) 222-7900
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange
Common Stock, par value $1.00 on which registered
and Preference Share Purchase Rights New York Stock Exchange
Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, par value $100
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months, and (2) has been
subject to such filing requirements for the past 90 days. Yes X. No __.
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of the Registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K. X
Indicate by check mark whether the registrant is an accelerated filer.
Yes X. No __.
State the aggregate market value of the voting stock held by
nonaffiliates of the registrant as of June 30, 2002: $1,877,769,000.
Indicate the number of shares outstanding of each of the
Registrant's classes of common stock, as of February 21, 2003:
74,042,667 shares.
DOCUMENTS INCORPORATED BY REFERENCE.
1. Pages 41 through 81 of the Registrant's Annual Report to
Stockholders for 2002 are incorporated by reference in Part II,
Items 6 and 8 of this Report.
2. Portions of the Registrant's Proxy Statement, dated March 7, 2003
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
Independent Power Production
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 and Related Stockholder
Matters
Item 13 -- Certain Relationships and Related
Transactions
Item 14 -- Controls and Procedures
PART IV
Item 15 -- Exhibits, Financial Statement Schedules and
Reports on Form 8-K
Signatures
Form 10-K Certifications
Exhibits
PART I
This Form 10-K contains forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
Forward-looking statements 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 - Risk Factors and Cautionary
Statements that May Affect Future Results. 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
in the northern Great Plains.
The Company, through its wholly owned subsidiary, Centennial
Energy Holdings, Inc. (Centennial), owns WBI Holdings, Inc. (WBI
Holdings), Knife River Corporation (Knife River), Utility
Services, Inc. (Utility Services), Centennial Energy Resources
LLC (Centennial Resources) and Centennial Holdings Capital LLC
(Centennial Capital).
WBI Holdings is comprised of the pipeline and energy
services and the natural gas and oil production
segments. The pipeline and energy services segment
provides natural gas transportation, underground storage
and gathering services through regulated and
nonregulated pipeline systems primarily in the Rocky
Mountain and northern Great Plains regions of the United
States. The pipeline and energy services segment also
provides energy-related management services, including
cable and pipeline magnetization and locating. The
natural gas and oil production segment is engaged in
natural gas and oil acquisition, exploration and
production activities primarily in the Rocky Mountain
region of the United States and in the Gulf of Mexico.
Knife River mines aggregates and markets crushed stone,
sand, gravel and related construction materials,
including ready-mixed concrete, cement, asphalt and other
value-added products, as well as performing integrated
construction services, in the north central and western
United States, including Alaska and Hawaii.
Utility Services is a diversified infrastructure company
specializing in 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 Resources owns electric generating facilities
in the United States. Electric capacity and energy
produced at these facilities is sold under long-term
contracts to nonaffiliated entities. Centennial
Resources also invests in potential new growth and
synergistic opportunities that are not directly being
pursued by the other business units. These activities
are reflected in the independent power production
segment.
Centennial Capital insures and reinsures various types of
risks as a captive insurer for certain of the Company's
subsidiaries. The function of the captive is to fund the
deductible layers of the insured companies' general
liability and automobile liability coverages. Centennial
Capital also owns certain real and personal property and
contract rights. These activities are reflected in the
independent power production segment.
The Company, through its wholly owned subsidiary, Centennial
Energy Resources International Inc (Centennial International),
has an investment in an electric generating facility in Brazil.
Electric capacity and energy produced at this facility is sold
under a long-term contract to a nonaffiliated entity. Centennial
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
independent power production segment.
As of December 31, 2002, the Company had 6,983 full-time
employees with 88 employed at MDU Resources Group, Inc., 898 at
Montana-Dakota, 57 at Great Plains, 432 at WBI Holdings, 3,022 at
Knife River's operations, 2,480 at Utility Services, five at
Centennial Resources and one at Centennial International. 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, 433
and 68 employees, respectively, are represented by the
International Brotherhood of Electrical Workers. Labor
contracts with such employees are in effect through April 30,
2003 and March 31, 2005, for Montana-Dakota and WBI Holdings,
respectively. Knife River has 40 labor contracts which represent
630 of its construction materials employees. Knife River is
currently in negotiations on 5 of its labor contracts. Utility
Services has 62 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.
During 2002, the Company underwent segment operating and
reporting changes. The financial results and data applicable to
each of the Company's business segments as well as their
financing requirements and a discussion regarding the previously
mentioned segment changes are set forth in Item 7 -- Management's
Discussion and Analysis of Financial Condition and Results of
Operations, Notes to the Consolidated Financial Statements and
Supplementary Financial Information.
Any reference to the Company's Consolidated Financial
Statements and Notes thereto and Supplementary Financial
Information shall be to pages 41 through 79 in the Company's
Annual Report to Stockholders for 2002 (Annual Report), which are
incorporated by reference herein.
This annual report on Form 10-K, the Company's quarterly
reports on Form 10-Q, the Company's current reports on Form 8-K
and any amendments to those reports filed or furnished pursuant
to Section 13(a) or 15(d) of the Securities Exchange Act of 1934
are available through the Company's website as soon as reasonably
practicable after the Company has filed such reports with the
Securities and Exchange Commission (SEC). The Company's website
address is www.mdu.com. The information available on the
Company's website is not part of this annual report on Form 10-K.
ELECTRIC
General --
Montana-Dakota provides electric service at retail, serving
over 116,000 residential, commercial, industrial and municipal
customers located in 177 communities and adjacent rural areas as
of December 31, 2002. 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, 2002, Montana-Dakota's net electric plant investment
approximated $274.2 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 2002 electric utility operating revenues by
jurisdiction is as follows: North Dakota -- 60 percent;
Montana -- 23 percent; South Dakota -- 7 percent and
Wyoming -- 10 percent.
System Supply and System Demand --
Through an interconnected electric system, Montana-Dakota
serves markets in portions of the following states and major
communities -- western North Dakota, including Bismarck,
Dickinson and Williston; eastern Montana, including Glendive and
Miles City; and northern South Dakota, including Mobridge. The
interconnected system consists of seven on-line electric
generating stations which have an aggregate turbine nameplate
rating attributable to Montana-Dakota's interest of 393,488
Kilowatts (kW) and a total summer net capability of 434,170 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.
On August 20, 2002, Montana-Dakota entered into an agreement
with Dakota I Power Partners (Dakota I) to purchase energy from a
20-megawatt wind energy farm in North Dakota. Dakota I is
expected to construct the project in 2003. The wind farm is in
close proximity to an existing Montana-Dakota transmission line.
The entire energy output will be dedicated to Montana-Dakota's
interconnected electric system. Regulatory approvals have been
obtained from the NDPSC and SDPUC for the wind farm project. The
wind farm project is subject to certain other regulatory
approvals.
Montana-Dakota plans to construct a 40-megawatt natural gas-
fired peaking unit. The unit is scheduled to be constructed for
operation by June 1, 2003. The project is expected to be
recovered in rates.
The following table sets forth details applicable to the
Company's electric generating stations:
2002 Net
Generation
Nameplate Summer (kilowatt-
Generating Rating Capability hours in
Station Type (kW) (kW) thousands)
North Dakota --
Coyote* Steam 103,647 106,750 787,703
Heskett Steam 86,000 104,050 523,025
Williston Combustion
Turbine 7,800 9,600 (70)**
South Dakota --
Big Stone* Steam 94,111 103,870 713,765
Montana --
Lewis & Clark Steam 44,000 52,300 286,514
Glendive Combustion
Turbine 34,780 33,800 4,453
Miles City Combustion
Turbine 23,150 23,800 1,590
393,488 434,170 2,316,980
- -----------------------------
* 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 March 2003, respectively.
Montana-Dakota is currently in negotiations with Westmoreland on
the Lewis & Clark station contract. 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, 1998, through
December 31, 2002, 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,
2002 2001 2000 1999 1998
Average cost of
coal per
million Btu $.98 $.92 $.94 $.90 $.93
Average cost of
coal per ton $14.39 $13.43 $13.68 $13.31 $13.67
The maximum electric peak demand experienced to date
attributable to sales to retail customers on the interconnected
system was 459,000 kW in July 2002. 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 2008 will approximate 0.8 percent annually.
Montana-Dakota's latest forecast indicates that its kilowatt-hour
(kWh) sales growth rate, on a normalized basis, through 2008 will
approximate 0.9 percent annually.
Montana-Dakota currently estimates that, with the addition of
a 40-megawatt natural gas turbine power plant and the purchase of
energy from a 20-megawatt wind farm in North Dakota, it has
adequate capacity available through existing generating stations
and long-term firm purchase contracts until the year 2005. If
additional capacity is needed in 2005 or after, it is expected to
be met through 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.
In December 2002, the Company confirmed its intent to continue
the 500-megawatt feasibility study, however the Company has
requested approval from the state of North Dakota to also include
within the study, an alternative 250-megawatt plant option.
Montana-Dakota has major interconnections with its
neighboring utilities, all of which are Mid-Continent Area Power
Pool (MAPP) members. Montana-Dakota considers these
interconnections adequate for coordinated planning, emergency
assistance, exchange of capacity and energy and power supply
reliability.
Through a separate electric system (Sheridan System), Montana-
Dakota serves Sheridan, Wyoming and neighboring communities. The
maximum peak demand experienced to date and attributable to
Montana-Dakota sales to retail consumers on that system was
approximately 51,200 kW and occurred in July 2002.
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) in September 2001. The
Midwest ISO, which the FERC accepted as a Regional Transmission
Organization under FERC Order No. 2000 in an order issued
in December 2001, is responsible for operational control of the
transmission systems of its members. Thereafter, in
December 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. In
December 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 in December 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 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 was based on a complaint filed
with the NDPSC in September 2001, by the NDPSC Staff. On April
24, 2002, the NDPSC issued an Order requiring Montana-Dakota to
reduce its North Dakota electric rates by $4.3 million annually,
effective May 8, 2002. On April 25, 2002, Montana-Dakota filed
an appeal of the NDPSC Order in the North Dakota South Central
Judicial District Court (District Court). The filing also
requested a stay of the effectiveness of the NDPSC Order while
the appeal was pending. Montana-Dakota challenged the NDPSC's
determination of the level of wholesale electricity sales margins
expected to be received by Montana-Dakota. On May 2, 2002, the
District Court granted Montana-Dakota's request for a stay of a
portion of the $4.3 million annual rate reduction ordered by the
NDPSC. Accordingly, Montana-Dakota implemented an annual rate
reduction of $800,000 effective with service rendered on and
after May 8, 2002, rather than the $4.3 million annual reduction
ordered by the NDPSC. The remaining $3.5 million was subject to
refund if Montana-Dakota did not prevail in this proceeding. On
November 22, 2002, the District Court issued an Order reversing
the decision of the NDPSC and remanded the case back to the
NDPSC. On January 15, 2003, the NDPSC issued an Order accepting
Montana-Dakota's level of wholesale electricity sales margins
thus reversing its initial decision and allowing Montana-Dakota
to continue to charge the electric rates which were in effect.
Montana-Dakota had established reserves for 2002 revenues
that had been collected subject to refund with respect to Montana-
Dakota's pending electric rate reduction. Based on the January
15, 2003, Order, as previously discussed, the reserves were
reversed and recognized in income in 2002.
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 that
will permit compliance with these laws or regulations, cannot be
accurately predicted. Montana-Dakota did not incur any material
environmental expenditures in 2002 and does not expect to incur
any material capital expenditures related to environmental
compliance with current laws and regulations through 2005.
NATURAL GAS DISTRIBUTION
General --
Montana-Dakota sells natural gas at retail, serving over
217,000 residential, commercial and industrial customers located
in 141 communities and adjacent rural areas as of December 31,
2002, and provides natural gas transportation services to certain
customers on its system. Great Plains sells natural gas at
retail, serving over 22,000 residential, commercial and
industrial customers located in 19 communities and adjacent rural
areas as of December 31, 2002, 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 and Great Plains' franchises, see Item
7 -- Management's Discussion and Analysis of Financial Condition
and Results of Operations. As of December 31, 2002,
Montana-Dakota's and Great Plains' net natural gas distribution
plant investment approximated $104.3 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 (MPUC) regarding retail
rates, service, accounting and, in certain instances, security
issuances. The percentage of Montana-Dakota's and Great Plains'
2002 natural gas utility operating revenues by jurisdiction is as
follows: North Dakota -- 37 percent; Minnesota -- 13 percent;
Montana -- 26 percent; South Dakota -- 19 percent and Wyoming --
5 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,
2002* 2001* 2000** 1999 1998
Mdk (thousands of decatherms)
Sales:
Residential 21,893 20,087 20,554 18,059 18,614
Commercial 16,044 14,661 14,590 12,030 12,458
Industrial 1,621 1,731 1,451 842 952
Total 39,558 36,479 36,595 30,931 32,024
Transportation:
Commercial 1,849 1,847 2,067 1,975 1,995
Industrial 11,872 12,491 12,247 9,576 8,329
Total 13,721 14,338 14,314 11,551 10,324
Total Throughput 53,279 50,817 50,909 42,482 42,348
Degree days
(% of normal) 101.1% 94.5% 100.4% 88.8% 93.7%
- -----------------------------
* 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. These bypasses did not have a material
effect on results of operations.
Montana-Dakota and Great Plains acquire their system
requirements directly from producers, processors and marketers.
Such natural gas is supplied by a portfolio of contracts
specifying market-based pricing, and is transported under
transportation agreements by Williston Basin, Kinder Morgan,
Inc., South Dakota Intrastate Pipeline Company, Northern Border
Pipeline Company, Viking Gas Transmission Company and Northern
Natural Gas Company to provide firm service to their customers.
Montana-Dakota has also contracted with Williston Basin to
provide firm storage services 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 --
On December 30, 2002, Montana-Dakota filed an application
with the SDPUC for a natural gas rate increase. Montana-Dakota
requested a total of $2.2 million annually or 5.8 percent above
current rates. A final order from the SDPUC is due June 30,
2003.
On October 7, 2002, Great Plains filed an application with
the MPUC for a natural gas rate increase. Great Plains requested
a total of $1.6 million annually or 6.9 percent above current
rates. On December 4, 2002, the MPUC issued an Order setting
interim rates that approved an interim increase of $1.4 million
annually effective December 6, 2002. Great Plains began
collecting such rates effective December 6, 2002, subject to
refund until the MPUC issues a final order. A final order from
the MPUC is due August 22, 2003.
On June 10, 2002, Montana-Dakota filed an application with
the WYPSC for a natural gas rate increase. Montana-Dakota
requested a total of $662,000 annually or 5.6 percent above
current rates. On December 9, 2002, the WYPSC approved an
increase of $466,000 annually effective January 1, 2003.
On May 20, 2002, Montana-Dakota filed an application with
MTPSC for a natural gas rate increase. Montana-Dakota requested
a total of $3.6 million annually or 6.5 percent above current
rates. On September 5, 2002, the MTPSC approved an interim
increase of $2.1 million annually, effective with service
rendered on and after September 5, 2002. Montana-Dakota began
collecting such rates effective September 5, 2002, which are
subject to refund until the MTPSC issues a final order. On
November 7, 2002, the MTPSC approved an additional interim
increase of $300,000 annually effective November 15, 2002. The
additional interim increase is the result of a Stipulation
reached between Montana-Dakota and the Montana Consumer Counsel,
the only intervener in the proceeding. Under the terms of the
Stipulation, the total interim relief granted ($2.4 million) will
be the final increase in the proceeding. A hearing before the
MTPSC was held on December 6, 2002, at which the MTPSC took under
advisement the Stipulation agreed upon by Montana-Dakota and the
Montana Consumer Counsel. A final order from the MTPSC was due
on February 20, 2003 and is currently pending.
On April 12, 2002, Montana-Dakota filed an application with
the NDPSC for a natural gas rate increase. Montana-Dakota
requested a total of $2.8 million annually or 4.1 percent above
current rates. On December 10, 2002, the NDPSC approved an
increase of $2.0 million annually, effective with service
rendered on or after December 12, 2002.
Reserves have been provided for a portion of the revenues
that have been collected subject to refund for certain of the
above proceedings. The Company believes that such reserves are
adequate based on its assessment of the ultimate outcome of the
proceedings.
Montana-Dakota's and Great Plains' retail natural gas rate
schedules contain clauses permitting monthly adjustments in rates
based upon changes in natural gas commodity, transportation and
storage costs. Current regulatory practices allow Montana-Dakota
and Great Plains to recover increases or refund decreases in such
costs within a period ranging from 24 months to 28 months from
the time such 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.
Governmental regulations establishing environmental
protection standards are continuously evolving and, therefore,
the character, scope, cost and availability of the measures that
will permit compliance with these laws or regulations, cannot be
accurately predicted. Montana-Dakota and Great Plains did not
incur any material environmental expenditures in 2002 and do not
expect to incur any material capital expenditures related to
environmental compliance with current laws and regulations
through 2005.
UTILITY SERVICES
General --
Utility Services is a diversified infrastructure company
specializing in electric, gas and telecommunication utility
construction, as well as industrial and commercial electrical,
exterior lighting and traffic signalization. Utility Services
also 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 2002, the Company acquired utility services businesses
based in California and Ohio. None of these acquisitions was
individually material to the Company.
Construction and maintenance crews are active year round.
However, activity in certain locations may be seasonal in nature
due to the effects of weather.
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,
2002, Utility Services owned or leased offices in eight states.
This space is used for offices, equipment yards, warehousing,
storage and vehicle shops. At December 31, 2002, Utility
Services' net plant investment was approximately $48.9 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, 2003, was approximately $152 million
compared to approximately $142 million at January 31, 2002. The
Company expects to complete a significant amount of the backlog
during the year ending December 31, 2003. Due to the nature of
its contractual arrangements, in many instances the Company's
customers are not committed to the specific volumes of services
to be purchased under a contract, but rather the Company is
committed to perform these services if and to the extent
requested by the customer. The customer is, however, obligated
to obtain these services from the Company if they are not
performed by the customer's employees. Therefore, there can be
no assurance as to the customer's requirements during a
particular period or that such estimates at any point in time are
predictive of future revenues.
Competition --
Utility Services operates in a highly competitive business
environment. Most of Utility Services' work is obtained on the
basis of competitive bids or by negotiation of either cost plus
or fixed price contracts. The workforce and equipment are highly
mobile, providing greater flexibility in the size and location of
Utility Services' market area. Competition is based primarily on
price and reputation for quality, safety and reliability. The
size and area location of the services provided as well as the
state of the economy will be factors in the number of competitors
that Utility Services will encounter on any particular project.
Utility Services believes that the diversification of the
services it provides, the market it serves throughout the United
States and the management of its workforce will enable it to
effectively operate in this competitive environment.
Utilities and independent contractors represent the largest
customer base. Accordingly, utility and sub-contract work
accounts for a significant portion of the work performed by the
utility services segment and the amount of construction contracts
is dependent to a certain extent on the level and timing of
maintenance and construction programs undertaken by customers.
Utility Services relies on repeat customers and strives to
maintain successful long-term relationships with these customers.
Environmental Matters --
Utility Services' operations are subject to regulation
customary for the industry, including federal, state and local
environmental compliance. Utility Services believes it is in
substantial compliance with those regulations.
Governmental regulations establishing environmental
protection standards are continuously evolving and, therefore,
the character, scope, cost and availability of the measures that
will permit compliance with these laws or regulations, cannot be
accurately predicted. Utility Services did not incur any
material environmental expenditures in 2002 and does not expect
to incur any material capital expenditures related to
environmental compliance with current laws and regulations
through 2005.
PIPELINE AND ENERGY SERVICES
General --
Williston Basin, the principal regulated business of WBI
Holdings, owns and operates approximately 3,500 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 and
interconnects with nine pipelines allowing for the receipt
and/or delivery of natural gas to and from other regions of
the country.
At December 31, 2002, Williston Basin's net plant
investment was approximately $160.2 million.
WBI Holdings, through its nonregulated pipeline businesses,
owns and operates gathering facilities in Colorado, Kansas,
Montana and Wyoming. These facilities include approximately
1,500 miles of field gathering lines and 79 owned and leased
compression facilities some of which interconnect with Williston
Basin's system. A one-sixth interest in the assets of various
offshore gathering pipelines and associated onshore pipeline and
related processing facilities are also owned by WBI Holdings. In
addition, WBI Holdings provides installation sales and/or leasing
of alternate energy delivery systems, primarily propane air
plants, as well as providing energy efficiency product sales and
installation services to large end users.
WBI Holdings, through its energy services businesses,
provides natural gas purchase and sales services to local
distribution companies, other marketers and a limited number of
large end users, primarily using natural gas produced by the
Company's natural gas and oil production segment. Energy
services transacts a significant portion of its business in the
Northern Plains and Rocky Mountain regions of the United States.
In 2001, the company sold the vast majority of its energy
marketing operations.
Energy services also owns a cable and pipeline magnetization
and locating company as well as a manufacturer and reseller of on-
land, hand-held locating equipment. The cable and pipeline
magnetization and locating company provides products and services
which are an integral part of the ongoing reliability of the
submerged cable and pipeline infrastructure. The on-land, hand-
held locating equipment company manufactures and resells
equipment that is used for locating and identifying underground
metal objects, utility systems and water distribution system
leaks. For additional information regarding these operations,
see Item 7 -- Management's Discussion and Analysis of Financial
Conditions and Results of Operations.
Under the Natural Gas Act, as amended, Williston Basin is
subject to the jurisdiction of the FERC regarding certificate,
rate, service and accounting matters.
System Demand and Competition --
Williston Basin competes with several pipelines for its
customers' transportation business and at times may discount
rates in an effort to retain market share. However, the strategic
location of Williston Basin's system near five natural gas
producing basins and the availability of underground storage and
gathering services provided by Williston Basin and affiliates
along with interconnections with other pipelines serve to enhance
Williston Basin's competitive position.
Although a significant portion of Williston Basin's firm
customers, which include Montana-Dakota, have relatively secure
residential and commercial end-users, virtually all have some
price-sensitive end-users that could switch to alternate fuels.
Williston Basin transports substantially all of Montana-
Dakota's natural gas utilizing firm transportation agreements,
which at December 31, 2002, represented 82 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.
In November 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 in late 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. For additional information regarding coalbed
natural gas legal proceedings, see Item 3 -- Legal Proceedings
and Item 7 -- Management's Discussion and Analysis of Financial
Condition and Results of Operations. 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.
In May 2001, the Administrative Law Judge issued an Initial
Decision on Williston Basin's natural gas rate change
application. This 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
Williston Basin's 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
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.
Governmental regulations establishing environmental
protection standards are continuously evolving and, therefore,
the character, scope, cost and availability of the measures that
will permit compliance with these laws or regulations, cannot be
accurately predicted. WBI Holdings' pipeline and energy
services' operations did not incur any material environmental
expenditures in 2002 and does not expect to incur any material
capital expenditures related to environmental compliance with
current laws and regulations through 2005.
NATURAL GAS AND OIL PRODUCTION
General --
Fidelity Exploration & Production Company (Fidelity), a
direct wholly owned subsidiary of WBI Holdings, is involved in
the acquisition, exploration, development and production of
natural gas and oil resources. Fidelity's activities include the
acquisition of producing properties with potential development
opportunities, exploratory drilling and the operation and
development of natural gas production properties. Fidelity also
shares revenues and expenses from the development of specified
properties located primarily in the Rocky Mountain region of the
United States and in 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 Montana and
Wyoming. For additional information regarding coalbed natural
gas legal proceedings, see Item 3 -- Legal Proceedings and Item 7
- -- Management's Discussion and Analysis of Financial Condition
and Results of Operations.
Fidelity continues to seek additional reserve and production
growth 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 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 2002, 2001 and 2000,
are as follows:
2002 2001 2000
Natural Gas:
Production (MMcf) 48,239 40,591 29,222
Average realized price $2.72 $3.78 $2.90
Oil:
Production (000's of barrels) 1,968 2,042 1,882
Average realized price $22.80 $24.59 $23.06
Production costs, including taxes,
per net equivalent Mcf $0.87 $0.84 $0.77
Well and Acreage Information --
Gross and net productive well counts and gross and net
developed and undeveloped acreage related to interests at
December 31, 2002, are as follows:
Gross Net
Productive Wells:
Natural Gas 2,479 1,998
Oil 2,250 134
Total 4,729 2,132
Developed Acreage (000's) 857 375
Undeveloped Acreage (000's) 703 343
Exploratory and Development Wells --
The following table shows the results of natural gas and oil
wells drilled and tested during 2002, 2001 and 2000:
Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total
2002 4 --- 4 201 --- 201 205
2001 19 1 20 590 2 592 612
2000 9 3 12 362 3 365 377
At December 31, 2002, there were 11 gross wells in the
process of drilling, all of which were development wells.
Fidelity had approximately 300 wells related to its coalbed
natural gas development in the Powder River Basin in Montana and
Wyoming that were not producing natural gas at December 31, 2002.
A large number of these wells are expected to begin producing
natural gas in 2003.
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.
Governmental regulations establishing environmental
protection standards are continuously evolving and, therefore,
the character, scope, cost and availability of the measures that
will permit compliance with these laws or regulations, cannot be
accurately predicted. In connection with the development of
coalbed natural gas properties certain capital expenditures were
incurred related to water handling. For 2002, capital
expenditures for water handling in compliance with current laws
and regulations were approximately $10.0 million and are
estimated to be less than $5.0 million for 2003.
Reserve Information --
Fidelity's recoverable proved developed and undeveloped
natural gas and oil reserves approximated 372.5 Bcf and 17.5
million barrels, respectively, at December 31, 2002.
For additional information related to natural gas and oil
interests, see Note 1 of Notes to Consolidated Financial
Statements and Supplementary Financial Information in the Annual
Report.
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 2002, the Company acquired several construction
materials and mining businesses with operations in Minnesota and
Montana. 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 September 30, 2003. Although it
is difficult to predict the outcome of legislation regarding
federal highway construction funding that is anticipated to
replace TEA-21 upon its expiration, the Company expects
replacement funding to be comparable to TEA-21. The Company
believes actual passage of the reauthorization legislation may
not occur until either the second or third quarter of 2003.
The construction materials business had approximately $244
million in backlog in mid-February 2003, compared to
approximately $162 million in mid-February 2002. The Company
anticipates that a significant amount of the current backlog will
be completed during the year ending December 31, 2003.
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:
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.
Consolidated Construction Materials and Mining:
Environmental Matters --
Knife River's construction materials and mining operations
are subject to regulation customary for such operations,
including federal, state and local environmental compliance and
reclamation regulations. Except as what may be ultimately
determined with regard to the issue described below, Knife River
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 that
will permit compliance with these laws or regulations, cannot be
accurately predicted. Knife River did not incur any material
environmental expenditures in 2002 and except as what may be
ultimately determined with regard to the issue described below,
Knife River does not expect to incur any material capital
expenditures related to environmental compliance with current
laws and regulations through 2005.
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.
The Company believes it is not probable that it will incur
any material environmental remediation costs or damages in
relation to the above administrative action.
Reserve Information --
As of December 31, 2002, the combined construction materials
operations had under ownership or lease approximately 1.1 billion
tons of recoverable aggregate reserves.
As of December 31, 2002, Knife River had under ownership or
lease, reserves of approximately 37.8 million tons of recoverable
lignite coal.
INDEPENDENT POWER PRODUCTION
Centennial Resources and Centennial International own
electric generating facilities in the United States and in
Brazil, respectively. Electricity produced at these facilities
is sold under long-term contracts to nonaffiliated entities.
This segment also invests in potential new growth and synergistic
opportunities that are not directly being pursued by the other
business units. Substantially all of the operations of the
independent power production began in 2002.
Domestic:
On November 1, 2002, Centennial Power, Inc. (Centennial
Power), an indirect wholly owned subsidiary of the Company,
purchased 213 megawatts of natural gas-fired electric generating
facilities (Brush Plant) near Brush, Colorado. Ninety-five
percent of the Brush Plant's output is sold to the Public
Service of Colorado, a wholly owned subsidiary of Xcel Energy,
under two power purchase contracts that expire in October 2005
and September 2012, respectively. The Brush Plant is operated
by Colorado Energy Management under two operations and
maintenance agreements that expire in October 2005 and April
2007, respectively.
Competition --
Centennial Power encounters competition in the development
of new electric generating plants and the acquisition of
existing generating facilities from other non-utility
generators, regulated utilities, nonregulated subsidiaries of
regulated utilities and other energy service companies as well
as financial investors. Competition for power sales agreements
may reduce prices in certain markets. The movement towards
deregulation in the U.S. electric power industry has also lead
to competition in the development and acquisition of domestic
power producing facilities. However, some states are
reconsidering their approach to deregulation. Factors for
competing in the power production industry include maintaining
low production costs, having a balanced portfolio of generating
assets, fuel types, customers and power sales agreements.
Environmental Matters --
The Brush Plant is subject to federal, state and local laws and
regulations providing for air, water and solid waste pollution
control; state facility-siting regulations; zoning and planning
regulations of certain state and local authorities; federal health
and safety regulations and state hazard communication standards.
Centennial Power believes it is in substantial compliance with those
regulations.
Governmental regulations establishing environmental
protection standards are continuously evolving and, therefore,
the character, scope, cost and availability of the measures that
will permit compliance with these laws or regulations, cannot be
accurately predicted. Centennial Power did not incur any
material environmental expenditures in 2002 and does not expect
to incur any material capital expenditures related to
environmental compliance with current laws and regulations
through 2005.
Other --
On January 31, 2003, Centennial Power purchased a 66.6-
megawatt wind-powered electric generation facility from San
Gorgonio Power Corporation, an affiliate of PG&E National Energy
Group, for $102.5 million cash, subject to certain closing
adjustments. This facility is located in the San Gorgonio Pass,
northwest of Palm Springs, California. The facility consists of
111 wind turbines and began commercial operation in September
2001. The facility sells all of its output under a long-term
contract with the California Department of Water Resources.
SeaWest Wind Power, Inc. will continue to operate the facility.
The plans to construct a 113-megawatt coal-fired electric
generation station near Hardin, Montana are pending. Centennial
Power acquired plant equipment and obtained all permits
necessary to begin construction. NorthWestern Energy terminated
the power purchase agreement for the energy from this plant in
July 2002; however Centennial Power is pursuing other markets
for the energy and is studying its options regarding this
project. Construction activities have been suspended except
those items of a critical nature. At December 31, 2002,
Centennial Power's investment in this project was approximately
$23.1 million. For additional information regarding this
project, see Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of Operations.
International:
In August 2001, Centennial 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 and coal
mining projects in Brazil. Centennial International has a 49
percent interest in MPX.
MPX, through a wholly owned subsidiary, has constructed a
200-megawatt natural gas-fired power plant (MPX Plant) in the
Brazilian state of Ceara. The first 100 megawatts entered
commercial service in July 2002 and the second 100 megawatts
entered commercial service in January 2003. Petrobras, the
partially Brazilian state-owned energy company, has agreed to
purchase all of the capacity and market all of the MPX Plant's
energy. Petrobras commenced making capacity payments in the
third quarter of 2002. The power purchase agreement with
Petrobras expires in May 2008. Petrobras also is under contract
for five years to supply natural gas to the MPX Plant. This
contract is renewable for an additional 13 years. At December
31, 2002, Centennial International's investment in the MPX Plant
was approximately $27.8 million. In addition, Centennial had
guaranteed certain MPX Plant obligations and loans of
approximately $24.9 million at December 31, 2002.
ITEM 3. LEGAL PROCEEDINGS
In January 2002, Fidelity Oil Co. (FOC), one of the Company's
natural gas and oil production subsidiaries, entered into a
compromise agreement with the former operator of certain of FOC's
oil production properties in southeastern Montana. The
compromise agreement resolved litigation involving the
interpretation and application of contractual provisions
regarding net proceeds interests paid by the former operator to
FOC for a number of years prior to 1998. The terms of the
compromise agreement are confidential. As a result of the
compromise agreement, the natural gas and oil production segment
reflected a nonrecurring gain in its financial results for the
first quarter of 2002 of approximately $16.6 million after tax.
As part of the settlement, FOC gave the former operator a full
and complete release, and FOC is not asserting any such claim
against the former operator for periods after 1997.
In 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 and 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. In May 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. In September 2001, the
defendants in this suit filed a motion to dismiss with the State
District Court. The motion to dismiss was denied by the State
District Court on August 19, 2002. 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. Williston Basin and Montana-Dakota believe
it is not probable that Grynberg and Quinque will ultimately
succeed given the current status of the litigation.
Fidelity Exploration & Production Company (Fidelity) has been
named as a defendant in several lawsuits filed in connection with
its coalbed natural gas development in the Powder River Basin in
Montana and Wyoming. Fidelity believes the ultimate outcome of
these actions will not have a material effect on its existing
coalbed natural gas operations. However, if the plantiffs were
successful, which Fidelity does not currently anticipate, the
ultimate outcome of the actions could have a material effect on
Fidelity's future development of its coalbed natural gas
properties. For additional information regarding this matter,
see Items 1 and 2 -- Business and Properties - Pipeline and
Energy Services and Natural Gas and Oil Production and Item 7 --
Management's Discussion and Analysis of Financial Condition and
Results of Operations.
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 matter, 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 2002.
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 2002 and 2001 and
dividends declared thereon were as follows:
Common
Common Common Stock
Stock Price Stock Price Dividends
(High) (Low) Per Share
2002
First Quarter $ 31.09 $ 27.25 $ .23
Second Quarter 33.45 25.75 .23
Third Quarter 27.40 18.00 .24
Fourth Quarter 25.99 20.91 .24
$ .94
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
As of December 31, 2002, the Company's common stock was held
by approximately 14,000 stockholders of record.
Between October 1, 2002 and December 31, 2002, the Company
issued 230,205 shares of Common Stock, $1.00 par value, as
partial consideration with respect to an acquisition during this
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
former owners of the business acquired, and now shareholders of
the Company, are accredited investors and have acknowledged that
they 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 80 and 81
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
Prior to the fourth quarter of 2002, the Company reported six
business segments consisting of electric, natural gas
distribution, utility services, pipeline and energy services,
natural gas and oil production and construction materials and
mining. During the fourth quarter of 2002, the Company added an
additional segment, independent power production, based on the
significance of this segment's operations. Substantially all of
the operations of the independent power production segment began
in 2002, therefore financial information for years prior to 2002
has not been presented.
The Company's operations are now conducted through seven
business segments. 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, and
energy related management services. Natural gas and oil
production includes the natural gas and oil acquisition,
exploration and production operations of WBI Holdings.
Construction materials and mining includes the results of Knife
River's operations, while independent power production includes
electric generating facilities in the United States and Brazil and
also invests in potential new growth and synergistic opportunities
that are not directly being pursued by other business segments.
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,
2002 2001 2000
Electric $ 15.8 $ 18.7 $ 17.7
Natural gas distribution 3.6 .7 4.8
Utility services 6.4 12.9 8.6
Pipeline and energy services 19.1 16.4 10.5
Natural gas and oil production 53.2 63.2 38.6
Construction materials and mining 48.7 43.2 30.1
Independent power production .9 --- ---
Earnings on common stock $ 147.7 $ 155.1 $ 110.3
Earnings per common share - basic $ 2.09 $ 2.31 $ 1.80
Earnings per common share - diluted $ 2.07 $ 2.29 $ 1.80
Return on average common equity 12.5% 15.3% 14.3%
2002 compared to 2001
Consolidated earnings for 2002 decreased $7.4 million from the
comparable period a year ago due to lower earnings at the natural
gas and oil production, utility services and electric businesses.
Increased earnings at the construction materials and mining,
natural gas distribution and pipeline and energy services
businesses, along with earnings from the independent power
production business, partially offset the earnings decline.
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.
________________________________
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,
2002 2001 2000
Operating revenues:
Retail sales $ 142.1 $ 137.3 $ 134.5
Sales for resale and other 20.5 31.5 27.1
162.6 168.8 161.6
Operating expenses:
Fuel and purchased power 56.0 57.4 54.1
Operation and maintenance 46.0 45.6 42.5
Depreciation, depletion and
amortization 19.6 19.5 19.1
Taxes, other than income 7.1 7.6 7.1
128.7 130.1 122.8
Operating income $ 33.9 $ 38.7 $ 38.8
Retail sales (million kWh) 2,275.0 2,177.9 2,161.3
Sales for resale (million kWh) 784.6 898.2 930.3
Average cost of fuel and
purchased power per kWh $ .018 $ .018 $ .016
Natural Gas Distribution
Years ended December 31,
2002 2001 2000
Operating revenues:
Sales $ 182.5 $ 251.3 $ 229.2
Transportation and other 4.1 4.1 3.9
186.6 255.4 233.1
Operating expenses:
Purchased natural gas sold 132.9 200.7 178.6
Operation and maintenance 36.5 36.6 32.0
Depreciation, depletion and
amortization 9.9 9.4 8.4
Taxes, other than income 4.9 5.1 4.6
184.2 251.8 223.6
Operating income $ 2.4 $ 3.6 $ 9.5
Volumes (MMdk):
Sales 39.6 36.5 36.6
Transportation 13.7 14.3 14.3
Total throughput 53.3 50.8 50.9
Degree days (% of normal) 101.1% 94.5% 100.4%
Average cost of natural gas,
including transportation
thereon, per dk $ 3.22 $ 5.50 $ 4.88
Utility Services
Years ended December 31,
2002 2001 2000
Operating revenues $ 458.7 $ 364.8 $ 169.4
Operating expenses:
Operation and maintenance 419.0 321.0 142.6
Depreciation, depletion and
amortization 9.9 8.4 4.9
Taxes, other than income 15.8 10.2 5.3
444.7 339.6 152.8
Operating income $ 14.0 $ 25.2 $ 16.6
Pipeline and Energy Services
Years ended December 31,
2002 2001 2000
Operating revenues:
Pipeline $ 95.3 $ 87.1 $ 77.4
Energy services 69.9 444.0 559.4
165.2 531.1 636.8
Operating expenses:
Purchased natural gas sold 58.3 433.5 548.3
Operation and maintenance 47.3 47.1 39.1
Depreciation, depletion and
amortization 14.8 14.3 15.3
Taxes, other than income 5.7 5.8 5.3
126.1 500.7 608.0
Operating income $ 39.1 $ 30.4 $ 28.8
Transportation volumes (MMdk):
Montana-Dakota 33.3 34.1 30.6
Other 66.6 63.1 56.2
99.9 97.2 86.8
Gathering volumes (MMdk) 72.7 61.1 41.7
Natural Gas and Oil Production
Years ended December 31,
2002 2001 2000
Operating revenues:
Natural gas $ 131.1 $ 153.3 $ 84.7
Oil 44.9 50.2 43.4
Other 27.6* 6.3 10.2
203.6 209.8 138.3
Operating expenses:
Purchased natural gas sold .1 2.8 3.4
Operation and maintenance 55.6 50.4 31.3
Depreciation, depletion and
amortization 48.7 41.7 27.0
Taxes, other than income 13.6 11.0 10.1
118.0 105.9 71.8
Operating income $ 85.6 $ 103.9 $ 66.5
Production:
Natural gas (MMcf) 48,239 40,591 29,222
Oil (000's of barrels) 1,968 2,042 1,882
Average realized prices:
Natural gas (per Mcf) $ 2.72 $ 3.78 $ 2.90
Oil (per barrel) $ 22.80 $ 24.59 $ 23.06
______________________________
* Includes the effects of a nonrecurring compromise agreement of
$27.4 million ($16.6 million after tax) in the first quarter
of 2002.
Construction Materials and Mining
Years ended December 31,
2002 2001 2000
Operating revenues:
Construction materials $ 962.3 $ 794.6 $ 597.7
Coal ---** 12.3** 33.7
962.3 806.9 631.4
Operating expenses:
Operation and maintenance 797.7 673.1 526.0
Depreciation, depletion and
amortization 54.4 46.6 36.2
Taxes, other than income 18.8 15.7 12.4
870.9 735.4 574.6
Operating income $ 91.4 $ 71.5 $ 56.8
Sales (000's):
Aggregates (tons) 35,078 27,565 18,315
Asphalt (tons) 7,272 6,228 3,310
Ready-mixed concrete
(cubic yards) 2,902 2,542 1,696
Coal (tons) ---** 1,171** 3,111
______________________________
** Coal operations were sold effective April 30, 2001.
Independent Power Production
Years ended December 31,
2002* 2001 2000
Operating revenues $ 6.8 $ --- $ ---
Operating expenses:
Operation and maintenance 6.4 --- ---
Depreciation, depletion and
amortization .7 --- ---
7.1 --- ---
Operating loss $ (.3) $ --- $ ---
Electricity produced and sold
(million kWh) 15.8 --- ---
______________________________
* Reflects international operations for 2002 and domestic
operations acquired in November 2002. The earnings from the
Company's equity method investment in Brazil were included in
other income - net.
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, utility services, construction materials and mining,
natural gas and oil production and independent power 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: $114.3
million, $98.8 million and $15.5 million for 2002; $113.2 million,
$107.7 million and $5.5 million for 2001; and $96.9 million, $96.0
million and $.9 million for 2000, respectively.
2002 compared to 2001
Electric
Electric earnings decreased as a result of lower average
realized sales for resale prices, which were 34 percent lower than
last year, due to weaker demand in the sales for resale markets;
the absence in 2002 of 2001 insurance recovery proceeds related to
a 2000 outage at an electric generating station; and lower sales
for resale volumes, which were 13 percent lower than last year.
Partially offsetting the earnings decline were increased retail
sales volumes, which were 4 percent higher than last year,
primarily to residential, commercial and large industrial
customers; decreased fuel and purchased power costs, largely lower
demand charges resulting from the absence of a 2001 extended
maintenance outage at an electric supplier's generating station;
and increased retail sales prices, primarily demand revenue, which
were partially offset by the North Dakota retail rate reduction.
For further information on the North Dakota retail rate reduction,
see Note 16 of Notes to Consolidated Financial Statements.
Natural Gas Distribution
Earnings at the natural gas distribution business increased as
a result of higher retail sales volumes, which were 8 percent
higher than last year, largely the result of weather that was 9
percent colder than the prior year; increased return on natural
gas storage, demand and prepaid commodity balances; increased
retail sales prices, largely the result of rate increases in
Minnesota, Montana and North Dakota; higher service and repair
margins; and lower income taxes, largely the result of the
reversal of certain tax contingency reserves. A reserve
adjustment of $3.3 million (after tax) related to certain pipeline
capacity charges partially offset the earnings increase. The pass-
through of lower natural gas prices resulted in the decrease in
sales revenues and purchased natural gas sold. For further
information on the retail rate increases, see Note 16 of Notes to
Consolidated Financial Statements.
Utility Services
Utility services earnings decreased as a result of lower line
construction margins in the Rocky Mountain region related
primarily to decreased fiber optic construction work; lower
construction margins in the Central region due to decreased inside
electrical work; the write-off of certain receivables and
restructuring of the engineering function of approximately $5.2
million (after tax); and decreased equipment sales and margins.
Partially offsetting the earnings decline were increased workloads
in the Southwest and Northwest regions, the discontinuance of the
amortization of goodwill in 2002 ($1.4 million after tax in 2001),
and decreased interest expense, primarily due to lower debt
balances. The increase in revenues and the related increase in
operation and maintenance expense resulted largely from businesses
acquired since the comparable period last year.
Pipeline and Energy Services
Earnings at the pipeline and energy services business increased
as a result of higher gathering revenues, largely increased
gathering volumes, which were 19 percent higher than last year, at
higher average rates, and higher stand-by fees; increased volumes
transported on-system and off-system, at slightly higher average
rates; and higher storage revenues. Also contributing to the
earnings improvement were lower corporate development costs and
the absence in 2002 of a 2001 write-off of an investment in a
software development company of $699,000 (after tax). Partially
offsetting the earnings increase were the net effects of the sale
of certain smaller nonstrategic properties in 2001 along with
higher operation and maintenance expense and higher depreciation,
depletion and amortization expense, a result of the gathering
system expansion to accommodate increasing natural gas volumes.
The $374.1 million decrease in energy services revenue and the
related decrease in purchased natural gas sold were due primarily
to decreased energy marketing volumes resulting from the sale of
the vast majority of the Company's energy marketing operations in
the third quarter of 2001.
Natural Gas and Oil Production
Natural gas and oil production earnings decreased largely due
to lower realized natural gas and oil prices, which were 28
percent and 7 percent lower than last year, respectively, along
with lower oil production of 4 percent; partially offset by higher
natural gas production of 19 percent, largely from operated
properties in the Rocky Mountain area. Also adding to the
earnings decline were increased depreciation, depletion and
amortization expense due to higher natural gas production volumes
and higher rates; increased operation and maintenance expense,
mainly higher lease operating expenses resulting from the
expansion of coalbed natural gas production; and lower sales
volumes of inventoried natural gas. Partially offsetting the
earnings decline were the effects of the nonrecurring compromise
agreement of $27.4 million ($16.6 million after tax), included in
operating revenues, as discussed in Note 17 of Notes to
Consolidated Financial Statements. Hedging activities for natural
gas and oil production for 2002 resulted in realized prices that
were 107 percent and 98 percent, respectively, of what otherwise
would have been received.
Construction Materials and Mining
Earnings for the construction materials and mining business
increased as a result of earnings from businesses acquired since
the comparable period last year; higher aggregate, asphalt and
cement sales volumes; increased construction revenues, largely the
result of several large projects mainly in California and Oregon;
and lower asphalt costs. Partially offsetting the increase in
earnings were the one-time gain in 2001 from the sale of the
Company's coal operations of $10.3 million ($6.2 million after
tax, including final settlement cost adjustments), included in
other income - net, as discussed in Note 12 of Notes to
Consolidated Financial Statements, as well as earnings from four
months of coal operations included in 2001 earnings. Higher
selling, general and administrative costs, mainly due to higher
computer support, insurance and payroll costs; and higher
depreciation, depletion and amortization expense due to higher
sales volumes, partially offset by the discontinuance of the
amortization of goodwill in 2002 ($1.7 million after tax in 2001),
also added to the partial offset in earnings.
Independent Power Production
Earnings at the independent power production segment totaled
$959,000. The majority of these earnings came from the newly
acquired 213-megawatt natural gas-fired electric generating
facilities in Colorado. The Brazilian operations also contributed
to earnings. The Company's 49 percent share of the gain of $13.6
million (after tax) from an embedded derivative in the electric
power contract and margins at the Brazil facilities were largely
offset by the Company's 49 percent share of the foreign currency
losses of $9.4 million (after tax) resulting from devaluation of
the Brazilian real and net interest expense of $3.6 million (after
tax).
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 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 12 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.
Risk Factors and Cautionary Statements that May Affect Future
Results
The Company is including the following factors and cautionary
statements in this Form 10-K to make applicable and to take
advantage of the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf of, the Company. Forward-looking statements
include statements concerning plans, objectives, goals,
strategies, future events or performance, and underlying
assumptions (many of which are based, in turn, upon further
assumptions) and other statements that are other than statements
of historical facts. From time to time, the Company may publish
or otherwise make available forward-looking statements of this
nature, including statements contained within Prospective
Information. All 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 factors and
cautionary statements.
Forward-looking statements involve risks and uncertainties,
which could cause actual results or outcomes to differ materially
from those expressed. The Company's expectations, beliefs and
projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including without limitation
management's examination of historical operating trends, data
contained in the Company's records and other data available from
third parties, but there can be no assurance that the Company's
expectations, beliefs or projections will be achieved or
accomplished.
Any forward-looking statement contained in this document 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.
Following are some specific factors that should be considered
for a better understanding of the Company's financial condition.
These factors and the other matters discussed herein are important
factors that could cause actual results or outcomes for the
Company to differ materially from those discussed in the forward-
looking statements included elsewhere in this document.
The recent events leading to the current adverse economic
environment may have a general negative impact on the Company's
future revenues.
In response to the occurrence of several recent events,
including the September 11, 2001, terrorist attack on the United
States, the ongoing war against terrorism by the United States and
the bankruptcy of several large energy and telecommunications
companies, the financial markets have been disrupted. An adverse
economy could negatively affect the level of governmental
expenditures on public projects and the timing of these projects
that, in turn, would negatively affect the demand for the
Company's products and services.
Innovatum, Inc. (Innovatum), an indirect wholly owned
subsidiary of the Company specializing in cable and pipeline
magnetization and locating, is subject to the economic conditions
within the telecommunications and energy industries. Innovatum
could face a future goodwill impairment if there is a continued
downturn in these sectors. At December 31, 2002, the goodwill
amount at Innovatum was approximately $8.3 million. The
determination of whether an impairment will occur is dependent on
a number of factors, including the level of spending in the
telecommunications and energy industries, the rapid changes in
technology, competitors and potential new customers.
The Company's natural gas and oil production business is dependent
on factors including commodity prices that cannot be predicted or
controlled.
These factors include price fluctuations in natural gas and
crude oil prices; availability of economic supplies of natural
gas; drilling successes in natural gas and oil operations; the
ability to contract for or to secure necessary drilling rig
contracts and to retain employees to drill for and develop
reserves; the ability to acquire natural gas and oil properties;
and other risks incidental to the operations of natural gas and
oil wells.
The Company's operations are weather sensitive.
The Company's results of operations can be affected by changes
in the weather. Weather conditions directly influence the demand
for electricity and natural gas, affect the price of energy
commodities and affect the ability to perform services at the
utility services and construction materials and mining businesses.
The Company cannot predict future weather conditions and as a
result, adverse weather conditions could negatively affect the
Company's operations and financial conditions.
The Company is subject to extensive environmental laws and
regulations that may increase its costs of operations, impact
or limit business plans, or expose the Company to
environmental liabilities.
The Company is subject to extensive environmental laws and
regulations affecting many aspects of its present and future
operations including air quality, water quality, waste management
and other environmental considerations. These laws and
regulations can result in increased capital, operating, and other
costs, as a result of compliance, remediation, containment and
monitoring obligations, particularly with regard to laws relating
to power plant emissions and coalbed natural gas development.
These laws and regulations generally require the Company to obtain
and comply with a wide variety of environmental licenses, permits,
inspections and other approvals. Both public officials and
private individuals may seek to enforce applicable environmental
laws and regulations. The Company cannot predict the outcome
(financial or operational) of any related litigation that may
arise.
There are no assurances that existing environmental regulations
will not be revised or that new regulations seeking to protect the
environment will not be adopted or become applicable to the
Company. Revised or additional regulations, which result in
increased compliance costs or additional operating restrictions,
particularly if those costs are not fully recoverable from
customers, could have a material effect on the Company's results
of operations.
Fidelity has been named as a defendant in several lawsuits
filed in connection with its coalbed natural gas development in
the Powder River Basin in Montana and Wyoming. Fidelity believes
the ultimate outcome of these actions would not have a material
effect on its existing coalbed natural gas operations. However,
if the plaintiffs are successful, which Fidelity does not
currently anticipate, the ultimate outcome of the actions could
have a material effect on Fidelity's future development of its
coalbed natural gas properties.
The Company is subject to extensive government regulations that
may have a negative impact on its business and its results of
operations.
The Company is subject to regulation by federal, state and
local regulatory agencies with respect to, among other things,
allowed rates of return, financings, industry rate structures,
recovery of purchased power and purchased gas costs. These
governmental regulations significantly influence the Company's
operating environment and may affect its ability to recover costs
from its customers. The Company is required to have numerous
permits, approvals and certificates from the agencies that
regulate its business. The Company believes the necessary
permits, approvals and certificates have been obtained for
existing operations and that the Company's business is conducted
in accordance with applicable laws; however, the Company is unable
to predict the impact on operating results from the future
regulatory activities of any of these agencies.
Changes in regulations or the imposition of additional
regulations could have an adverse impact on the Company's results
of operations.
The Company is dependent on its ability to successfully access
capital markets. Inability to access capital may limit its
ability to execute business plans, pursue improvements or make
acquisitions that it may otherwise rely on for future growth.
The Company relies on access to both short-term borrowings,
including the issuance of commercial paper, and long-term capital
markets as a significant source of liquidity for capital
requirements not satisfied by the cash flow from its operations.
If the Company is not able to access capital at competitive rates,
the ability to implement its business plans may be adversely
affected. Market disruptions or a downgrade of its credit ratings
may increase the cost of borrowing or adversely affect its ability
to access one or more financial markets. Such disruptions could
include:
- A severe economic downturn
- The bankruptcy of unrelated companies in the same line of
business
- Capital market conditions generally
- Commodity prices
- Terrorist attacks
- Global events
There are risks involved with the growth strategies of the
Company's independent power production business.
The operation of power generation facilities involves many
risks, including start up risks, breakdown or failure of
equipment, competition, inability to obtain required governmental
permits and approvals and inability to negotiate acceptable
acquisition, construction, fuel supply or other material
agreements, as well as the risk of performance below expected
levels of output or efficiency.
The Company's plans to construct a 113-megawatt coal-fired
electric generation station in Montana are pending. The Company
purchased plant equipment and obtained all permits necessary to
begin construction. NorthWestern Energy terminated the power
purchase agreement for the energy from this plant in July 2002;
however, the Company is pursuing other markets for the energy and
is studying its options regarding this project. The Company has
suspended construction activities except for those items of a
critical nature. At December 31, 2002, the Company's investment
in this project was approximately $23.1 million. If it is not
economically feasible for the Company to construct and operate
this facility or if alternate markets cannot be identified, an
asset impairment may occur.
The value of the Company's investment in foreign operations may
diminish due to political, regulatory and economic conditions and
changes in currency rates in countries where the Company does
business.
The Company is subject to political, regulatory and economic
conditions and changes in currency rates in foreign countries
where the Company does business. Significant changes in the
political, regulatory or economic environment in these countries
could negatively affect the value of the Company's investments
located in these countries. Also, since the Company is unable to
predict the fluctuations in the foreign currency exchange rates,
these fluctuations may have an adverse impact on the Company's
results of operations.
The Company's 49 percent equity method investment in a 200-
megawatt natural gas-fired electric generation project in Brazil
includes a power purchase agreement that contains an embedded
derivative. This embedded derivative derives its value from an
annual adjustment factor that largely indexes the contract
capacity payments to the U.S. dollar. In addition, from time to
time, other derivative instruments may be utilized. The valuation
of these financial instruments, including the embedded derivative,
can involve judgments, uncertainties and the use of estimates. As
a result, changes in the underlying assumptions could affect the
reported fair value of these instruments. These instruments could
recognize financial losses as a result of volatility in the
underlying fair values, or if a counterparty fails to perform.
Competition is increasing in all of the Company's businesses.
All of the Company's business segments are subject to increased
competition. The independent power industry includes numerous
strong and capable competitors, many of which have extensive
experience in the operation, acquisition and development of power
generation facilities. Utility services' competition is based
primarily on price and reputation for quality, safety and
reliability. The construction materials products are marketed
under highly competitive conditions and are subject to such
competitive forces as price, service, delivery time and proximity
to the customer. The electric utility and natural gas industries
are also experiencing increased competitive pressures as a result
of consumer demands, technological advances, deregulation, greater
availability of natural gas-fired generation and other factors.
Pipeline and energy services competes with several pipelines for
access to natural gas supplies and gathering, transportation and
storage business. The natural gas and oil production business is
subject to competition in the acquisition and development of
natural gas and oil properties.
Other important factors that could cause actual results or
outcomes for the Company to differ materially from those discussed
in forward-looking statements include:
- Acquisition and disposal of assets or facilities
- Changes in operation and construction of plant facilities
- Changes in present or prospective generation
- Changes in anticipated tourism levels
- The availability of economic expansion or development
opportunities
- Population growth rates and demographic patterns
- Market demand for energy 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
- 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
- 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
and its subsidiaries over the next few years and other matters for
each of the Company's seven 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 Risk Factors and Cautionary Statements that May Affect
Future Results. Changes in such assumptions and factors could
cause actual future results to differ materially from targeted
growth, revenue and earnings projections.
MDU Resources Group, Inc.
- - 2003 earnings per share, diluted, before the cumulative
effect of an accounting change required by the implementation of
Statement of Financial Accounting Standards No. 143, "Accounting
for Asset Retirement Obligations" (SFAS No. 143) in the first
quarter of 2003, are projected in the range of $1.80 to $2.05.
- - The Company expects the percentage of 2003 earnings per share
before the cumulative effect of an accounting change by quarter to
be in the following approximate ranges:
- First Quarter: 5 percent to 10 percent
- Second Quarter: 20 percent to 25 percent
- Third Quarter: 40 percent to 45 percent
- Fourth Quarter: 25 percent to 30 percent
- - The Company will examine issuing equity from time to time to
keep debt at the nonregulated businesses at no more than 40
percent of total capitalization.
- - The Company's long-term compound annual growth goals on
earnings per share from operations are in the range of 6 percent
to 9 percent.
Electric
- - Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric operations in
all of the municipalities it serves where such franchises are
required. As franchises expire, Montana-Dakota may face
increasing competition in its service areas, particularly its
service to smaller towns, from rural electric cooperatives.
Montana-Dakota intends to protect its service area and seek
renewal of all expiring franchises and will continue to take steps
to effectively operate in an increasingly competitive environment.
- - A 40-megawatt natural gas-fired peaking unit is scheduled to
be constructed for operation by June 1, 2003. This project is
expected to be recovered in rates and will be used to meet the
utility's need for additional generating capacity.
- - Pending regulatory approval, Montana-Dakota plans to purchase
energy from a 20-megawatt wind energy farm in North Dakota. Rate
recovery is expected.
- - Montana-Dakota 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. In December 2002,
Montana-Dakota confirmed its intent to continue the study,
however, Montana-Dakota is also in the process of obtaining
approval to include a 250-megawatt plant option within the study.
The next preliminary decision is expected in late 2003.
Natural gas distribution
- - Montana-Dakota and Great Plains have obtained and hold valid
and existing franchises authorizing them to conduct their natural
gas operations in all of the municipalities they serve where such
franchises are required. As franchises expire, Montana-Dakota and
Great Plains may face increasing competition in their service
areas. Montana-Dakota and Great Plains intend to protect their
service areas and seek renewal of all expiring franchises and will
continue to take steps to effectively operate in an increasingly
competitive environment.
- - Annual natural gas throughput for 2003 is expected to be
approximately 50 million decatherms.
- - Montana-Dakota or Great Plains have filed applications with
state regulatory authorities in three states (Minnesota, Montana
and South Dakota) seeking increases in natural gas retail rates
that are in the range of 5.8 percent to 6.9 percent above current
rates. While Montana-Dakota and Great Plains believe that they
should be authorized to increase retail rates in the respective
amounts requested, there is no assurance that the increases
ultimately allowed will be for the full amounts requested in each
jurisdiction. For further information on the natural gas rate
increase applications, see Note 16 of Notes to Consolidated
Financial Statements.
Utility services
- - Revenues for this segment are expected to be in the range of
$450 million to $500 million in 2003. This segment anticipates
margins in 2003 to increase over 2002 levels.
Pipeline and energy services
- - In 2003, natural gas throughput from this segment, including
both transportation and gathering, is expected to increase
slightly over the 2002 record level throughput.
- - A 247-mile pipeline to transport additional natural gas to
market and enhance the use of this segment's storage facilities is
currently under regulatory review. Depending upon the timing of
receiving the necessary regulatory approval, completion of
construction could occur in late 2003.
- - Innovatum could face a future goodwill impairment based on
certain economic conditions, as previously discussed in Risk
Factors and Cautionary Statements that May Affect Future Results.
Natural gas and oil production
- - In 2003, this segment expects a combined natural gas and oil
production increase in excess of 20 percent over 2002 record
levels.
- - This segment expects to drill in excess of 400 wells in 2003.
- - This segment had approximately 300 wells related to its
coalbed natural gas development in the Powder River Basin in
Montana and Wyoming that were not producing natural gas at
December 31, 2002. A large number of these wells are expected to
begin producing natural gas in 2003.
- - Natural gas prices in the Rocky Mountain region for February
through December 2003 reflected in the Company's 2003 earnings
guidance are in the range of $2.50 to $3.00 per Mcf. The
Company's estimates for natural gas prices on the NYMEX for
February through December 2003 reflected in the Company's 2003
earnings guidance are in the range of $3.00 to $3.50 per Mcf.
During 2002, more than half of this segment's natural gas
production was priced using Rocky Mountain or other non-NYMEX
prices.
- - NYMEX crude oil prices for January through December 2003
reflected in the Company's 2003 earnings guidance are in the range
of $20 to $25 per barrel.
- - This segment has hedged a portion of its 2003 production
primarily using collars that establish both a floor and a cap. The
Company has entered into agreements representing approximately 40
percent to 45 percent of 2003 estimated annual natural gas
production. The agreements are at various indices and range from
a low CIG index of $2.94 to a high Ventura index of $4.76 per Mcf.
- - The Company has hedged a portion of its 2003 oil production.
The Company has entered into agreements at NYMEX prices with
floors of $24.50 and caps as high as $28.12 per barrel,
representing approximately 30 percent to 35 percent of 2003
estimated annual oil production.
- - Fidelity has been named as a defendant in several lawsuits
filed in connection with its coalbed natural gas development in
the Powder River Basin in Montana and Wyoming, as previously
discussed in Risk Factors and Cautionary Statements that May
Affect Future Results.
Construction materials and mining
- - Excluding the effects of potential future acquisitions,
aggregate, asphalt and ready-mixed concrete volumes are expected
to remain at or near the record levels achieved in 2002.
- - Revenues for this segment in 2003 are expected to be
unchanged from 2002 record levels.
Independent power production
- - Earnings projections for 2003 for the independent power
production segment include the estimated results from the
previously mentioned wind-powered electric generation facility and
the 2002 acquisition of generating facilities in Colorado, as well
as earnings from the 200-megawatt natural gas-fired generation
project in Brazil. Earnings from this segment are expected to be
in the range of $12 million to $17 million in 2003.
- - On January 31, 2003, this segment purchased a 66.6-megawatt
Mountain View wind-powered electric generating facility. The
project sells all of its output under a long-term contract with
the California Department of Water Resources.
- - The Company's plans to construct a 113-megawatt coal-fired
electric generation station in Montana are pending as previously
discussed in Risk Factors and Cautionary Statements that May
Affect Future Results.
New Accounting Standards
In June 2001, the Financial Accounting Standards Board (FASB)
approved SFAS No. 143. The adoption of SFAS No. 143 is expected
to result in a one-time cumulative effect after-tax charge to
earnings in the range of $7.0 million to $10.0 million and is also
estimated to reduce 2003 earnings before the cumulative effect
charge by approximately $1.6 million to $2.1 million. In
addition, a regulatory asset that is approximated to be less than
$1.0 million will be recognized for the transition amount that is
expected to be recovered in rates over time. The Company intends
to record the cumulative charge and regulatory asset in the first
quarter of 2003.
In April 2002, the FASB approved Statement of Financial
Accounting Standards No. 145, "Rescission of FASB Statements No.
4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" (SFAS No. 145). The Company believes the adoption of
SFAS No. 145 will not have a material effect on its financial
position or results of operations.
In June 2002, the FASB approved Statement of Financial
Accounting Standards No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 is
to be applied prospectively to exit or disposal activities
initiated after December 31, 2002, and is not expected to have a
material effect on the Company's financial position or results of
operations.
In September 2002, the Emerging Issues Task Force (EITF)
issued consensus in EITF Issue No. 02-13, "Deferred Income Tax
Considerations in Applying the Goodwill Impairment Test in FASB
Statement No. 142, Goodwill and Other Intangible Assets" (EITF No.
02-13). EITF No. 02-13 did not have a material effect on the
Company's goodwill impairment testing.
In October 2002, the EITF issued consensus in EITF Issue No.
02-3, "Issues Involved in Accounting for Derivative Contracts Held
for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities" (EITF No. 02-3). The adoption of EITF
No. 02-3 did not have a material effect on the Company's financial
position or results of operations.
In November 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others" (Interpretation No. 45). The Company will apply the
initial recognition and initial measurement provisions of
Interpretation No. 45 to guarantees issued or modified after
December 31, 2002.
In December 2002, the FASB approved Statement of Financial
Accounting Standards No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure - an amendment of FASB
Statement No. 123" (SFAS No. 148). The Company had adopted the
disclosure provisions of SFAS No. 148 at December 31, 2002.
For further information on SFAS No. 143, SFAS No. 145, SFAS
No. 146, EITF No. 02-13, EITF No. 02-3, Interpretation No. 45 and
SFAS No. 148, 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
of America, 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 Statement of Financial Accounting Standards No. 142,
"Goodwill and Other Intangibles." Unforeseen events and changes
in circumstances and market conditions and material differences in
the value of long-lived assets and intangibles due to changes in
estimates of future cash flows could negatively affect the fair
value of the Company's assets and result in an impairment charge.
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
revenue 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 assumptions to be made
when estimating and valuing reserves using specific point in time
natural gas and oil prices. 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 of America 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
Certain subsidiaries of the Company have cash flow hedging
instruments comprised of natural gas price swap and natural gas
and oil collar agreements and a foreign currency collar agreement
that has not been designated as a hedge. The fair values of the
natural gas price swap and natural gas and oil collar agreements
and the foreign currency collar agreement have been recorded on
the Company's balance sheet. The objective for holding the
natural gas price swap and natural gas and oil collar 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. The objective
for holding the foreign currency collar agreement is to manage a
portion of the Company's foreign currency risk. For more
information on the Company's derivative instruments, see Note 5 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 or due to fluctuations in
foreign currency exchange rates. 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.
Use of estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires the Company to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and
expenses during the reporting period. Estimates are used for
items such as impairment testing of long-lived assets, goodwill
and natural gas and oil properties; fair values of acquired assets
and liabilities under the purchase method of accounting; natural
gas and oil reserves; property depreciable lives; tax provisions;
uncollectible accounts; environmental and other loss
contingencies; accumulated provision for revenues subject to
refund; costs on construction contracts; unbilled revenues;
actuarially determined benefit costs; the valuation of stock-based
compensation; and the fair value of an embedded derivative in a
power purchase agreement related to an equity method investment in
Brazil as discussed in Note 2 of Notes to Consolidated Financial
Statements. 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.
Liquidity and Capital Commitments
Cash flows
Operating activities --
Cash flows provided by operating activities in 2002 decreased
$22.2 million compared to 2001, largely the result of a decrease
in cash from working capital items of $58.4 million. Higher
depreciation, depletion and amortization expense of $18.0 million,
resulting largely from increased property, plant and equipment
balances, along with an increase in other noncurrent changes of
$15.7 million partially offset the decrease in cash flows from
operating activities.
In 2001, cash flows from operating activities 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.
Investing activities --
Cash flows used in investing activities in 2002 increased $6.2
million compared to 2001, the result of an increase in net capital
expenditures (capital expenditures, acquisitions, net of cash
acquired, and net proceeds from the sale or disposition of
property) of $22.6 million and an increase in investments of $7.4
million, partially offset by a decrease in notes receivable of
$23.8 million. Net capital expenditures exclude the noncash
transactions related to acquisitions, including the issuance of
the Company's equity securities. The noncash transactions were
$47.2 million and $57.4 million for the years ended December 31,
2002 and 2001, respectively.
In 2001, cash flows used in investing activities 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 receivable 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.
Financing activities --
Cash flows provided by financing activities in 2002 increased
$48.8 million compared to 2001, primarily the result of the
decrease of the repayment of long-term debt of $32.5 million and
the net increase of short-term borrowings of $28.0 million,
partially offset by the decrease in proceeds from issuance of
common stock of $12.0 million.
In 2001, financing activities resulted in a decrease in cash
flows 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.
Defined benefit pension plans
The Company has qualified noncontributory defined benefit
pension plans (Pension Plans). Various actuarial assumptions are
used in calculating the benefit expense (income) and liability
(asset) related to the Pension Plans. Actuarial assumptions
include assumptions about the discount rate, expected return on
plan assets and rate of future compensation increases as
determined by the Company within certain guidelines. During the
year ended December 31, 2002, the market value of plan assets was
negatively affected by persistent declines in the equity markets.
At December 31, 2002, certain noncontributory defined benefit
pension plans' accumulated benefit obligations exceeded these
plans' assets by approximately $4.9 million. Pretax pension
income reflected in the years ended December 31, 2002, 2001 and
2000, was $2.4 million, $4.4 million and $4.4 million,
respectively. The change in pension income for the year ended
December 31, 2003, is not expected to significantly affect
earnings as a result of the impact of recent declines in the
market value of Pension Plan assets. For further information on
the Company's Pension Plans, see Note 14 of Notes to Consolidated
Financial Statements.
Capital expenditures
The Company's capital expenditures (in millions) for 2000
through 2002 and as anticipated for 2003 through 2005 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*
2000 2001 2002 Capital expenditures: 2003 2004 2005
$ 15.8 $ 14.4 $ 27.8 Electric $ 32.7 $ 21.5 $ 26.8
21.3 14.7 11.0 Natural gas distribution 15.2 13.0 12.8
42.6 70.2 17.3 Utility services 10.5 10.4 11.2
Pipeline and energy
69.0 51.0 21.5 services 72.5 21.9 19.2
Natural gas and oil
173.5 118.7 136.4 production 123.0 112.1 107.1
Construction materials
218.7 170.6 106.9 and mining 48.6 52.9 49.1
Independent power
--- --- 95.7 production 166.1 1.1 1.1
540.9 439.6 416.6 468.6 232.9 227.3
Net proceeds from sale or
(11.0) (51.6) (16.2) disposition of property (4.9) (.8) (1.1)
529.9 388.0 400.4 Net capital expenditures 463.7 232.1 226.2
Retirement of long-term
29.4 115.2 82.6 debt and preferred stock 22.2 173.9 70.4
$559.3 $503.2 $483.0 $485.9 $406.0 $296.6
_________________________
*The estimated 2003 through 2005 capital expenditures reflected
in the above table exclude potential future acquisitions other
than the previously disclosed purchase of a 66.6-megawatt wind-
powered electric generation facility. The Company continues to
evaluate potential future acquisitions; however, these
acquisitions are dependent upon the availability of economic
opportunities and, as a result, capital expenditures may vary
significantly from the above estimates.
Capital expenditures for 2002, 2001 and 2000, related to
acquisitions, in the preceding table include the following noncash
transactions: issuance of the Company's equity securities of
$47.2 million in 2002; issuance of the Company's equity securities
of $57.4 million in 2001; and issuance of the Company's equity
securities and the conversion of a note receivable to purchase
consideration of $132.1 million in 2000.
In 2002, the Company acquired a number of businesses, none of
which was individually material, including utility services
companies in California and Ohio, construction materials and
mining businesses in Minnesota and Montana, an energy development
company in Montana and natural gas-fired electric generation
facilities in Colorado. The total purchase consideration for
these businesses, consisting of the Company's common stock and
cash, was $139.8 million.
The 2002 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 2003 through 2005 include those
for system upgrades, including a 40-megawatt natural gas-fired
peaking unit, as previously discussed; routine replacements;
service extensions; routine equipment maintenance and
replacements; land and building improvements; pipeline and
gathering expansion projects, including a 247-mile pipeline, as
previously discussed; the further enhancement of natural gas and
oil production and reserve growth; power generation opportunities,
including the acquisition of a 66.6-megawatt wind-powered electric
generation facility and construction of a 113-megawatt coal-fired
electric generation station, both as previously discussed; and for
other growth opportunities. The Company continues to evaluate
potential future acquisitions and other growth opportunities;
however, they are dependent upon the availability of economic
opportunities and, as a result, capital expenditures may vary
significantly from the estimates in the preceding table. It is
anticipated that all of the funds required for capital
expenditures and retirements of long-term debt and preferred stock
for the years 2003 through 2005 will be met from various sources.
These sources include internally generated funds, commercial paper
credit facilities at Centennial and MDU Resources Group, Inc., as
described below, and through the issuance of long-term debt and
the Company's equity securities.
Capital resources
Certain debt instruments of the Company and its subsidiaries,
including those discussed below, contain restrictive covenants,
all of which the Company and its subsidiaries were in compliance
with at December 31, 2002.
MDU Resources Group, Inc.
The Company has unsecured short-term bank lines of credit from
several banks totaling $46 million and a revolving credit
agreement with various banks totaling $50 million at December 31,
2002. The bank lines of credit provide for commitment fees at
varying rates and there were no amounts outstanding under the bank
lines of credit or the credit agreement at December 31, 2002. The
bank lines of credit and the credit agreement support the
Company's $75 million commercial paper program. Under the
Company's commercial paper program, $58.0 million was outstanding
at December 31, 2002, of which $8.0 million was classified as
short-term borrowings and $50.0 million was classified as long-
term debt. The commercial paper borrowings classified as short
term are supported by the short-term bank lines of credit. The
commercial paper borrowings classified as long-term debt are
intended to be refinanced on a long-term basis through continued
Company commercial paper borrowings supported by the credit
agreement, which allows for subsequent borrowings up to a term of
one year. The Company intends to renew or replace the existing
credit agreement, which expires December 30, 2003.
The Company's goal is to maintain acceptable credit ratings in
order to access the capital markets through the issuance of
commercial paper. If the Company were to experience a minor
downgrade of its credit rating, it would not anticipate any change
in its ability to access the capital markets. However, in such
event, the Company would expect a nominal basis point increase in
overall interest rates with respect to its cost of borrowings. If
the Company were to experience a significant downgrade of its
credit ratings, which it does not currently anticipate, it may
need to borrow under its credit agreement and/or bank lines of
credit.
To the extent the Company needs to borrow under its credit
agreement and/or its bank lines of credit, it would be expected to
incur increased annualized interest expense on its variable rate
debt of approximately $87,000 (after tax) based on December 31,
2002, variable rate borrowings. Based on the Company's overall
interest rate exposure at December 31, 2002, this change would not
have a material effect on the Company's results of operations or
cash flows.
On an annual basis, the Company negotiates the placement of its
credit agreement and bank lines of credit that provide credit
support to access the capital markets. In the event the Company
was unable to successfully negotiate the credit agreement and/or
the bank lines of credit, or in the event the fees on such
facilities became too expensive, which it does not currently
anticipate, the Company would seek alternative funding. One
source of alternative funding might involve the securitization of
certain Company assets.
In order to borrow under the Company's credit agreement, the
Company must be in compliance with the applicable covenants and
certain other conditions. The significant covenants include
maximum leverage ratios, minimum interest coverage ratio,
limitation on sale of assets and limitation on investments. The
Company was in compliance with these covenants and met the
required conditions at December 31, 2002. In the event the
Company does not comply with the applicable covenants and other
conditions, alternative sources of funding may need to be pursued
as previously described.
Currently, there are no credit facilities that contain cross-
default provisions between the Company and any of its
subsidiaries.
The Company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of its
Indenture of Mortgage. Generally, those restrictions require the
Company to 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, 2002, the Company could have issued
approximately $327 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 4.8 times and 5.3 times for the years ended
December 31, 2002 and 2001, respectively. Additionally, the
Company's first mortgage bond interest coverage was 7.7 times and
8.5 times for the years ended December 31, 2002 and 2001,
respectively. Common stockholders' equity as a percent of total
capitalization was 60 percent and 58 percent at December 31, 2002
and 2001, respectively.
Centennial Energy Holdings, Inc.
Centennial has a revolving credit agreement with various banks
that supports $305 million of Centennial's $350 million commercial
paper program. There were no outstanding borrowings under the
Centennial credit agreement at December 31, 2002. Under the
Centennial commercial paper program, $101.9 million was
outstanding at December 31, 2002. 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 26, 2003.
Centennial has an uncommitted long-term master shelf agreement
that allows for borrowings of up to $400 million. Under the terms
of the master shelf agreement, $360.6 million was outstanding at
December 31, 2002. On January 17, 2003, Centennial borrowed an
additional $39.0 million under the terms of this agreement. The
$39.0 million in proceeds was used to pay down Centennial
commercial paper program borrowings. In the future, Centennial
intends to pursue other financing arrangements, including private
and/or public financing.
Centennial's goal is to maintain acceptable credit ratings in
order to access the capital markets through the issuance of
commercial paper. If Centennial were to experience a minor
downgrade of its credit rating, it would not anticipate any change
in its ability to access the capital markets. However, in such
event, Centennial would expect a nominal basis point increase in
overall interest rates with respect to its cost of borrowings. If
Centennial were to experience a significant downgrade of its
credit ratings, which it does not currently anticipate, it may
need to borrow under its committed bank lines.
To the extent Centennial needs to borrow under its committed
bank lines, it would be expected to incur increased annualized
interest expense on its variable rate debt of approximately
$153,000 (after tax) based on December 31, 2002, variable rate
borrowings. Based on Centennial's overall interest rate exposure
at December 31, 2002, this change would not have a material effect
on the Company's results of operations or cash flows.
On an annual basis, Centennial negotiates the placement of the
Centennial credit agreement that provides credit support to access
the capital markets. In the event Centennial was unable to
successfully negotiate the credit agreement, or in the event the
fees on such facility became too expensive, which Centennial does
not currently anticipate, it would seek alternative funding. One
source of alternative funding might involve the securitization of
certain Centennial assets.
In order to borrow under Centennial's credit agreement and the
Centennial uncommitted long-term master shelf agreement,
Centennial and certain of its subsidiaries must be in compliance
with the applicable covenants and certain other conditions. The
significant covenants include maximum capitalization ratios,
minimum interest coverage ratios, minimum consolidated net worth,
limitation on priority debt, limitation on sale of assets and
limitation on loans and investments. Centennial and such
subsidiaries were in compliance with these covenants and met the
required conditions at December 31, 2002. In the event Centennial
or such subsidiaries do not comply with the applicable covenants
and other conditions, alternative sources of funding may need to
be pursued as previously described.
The Centennial credit agreement and the Centennial uncommitted
long-term master shelf agreement contain cross-default provisions.
These provisions state that if Centennial or any subsidiary of
Centennial fails to make any payment with respect to any
indebtedness or contingent obligation, in excess of a specified
amount, under any agreement that causes such indebtedness to be
due prior to its stated maturity or the contingent obligation to
become payable, the Centennial credit agreement and the Centennial
uncommitted long-term master shelf agreement will be in default.
The Centennial credit agreement, the Centennial uncommitted long-
term master shelf agreement and Centennial's practice limit the
amount of subsidiary indebtedness.
International operations
A subsidiary of the Company, that has an investment in electric
generating facilities in Brazil, has a short-term credit agreement
that allows for borrowings of up to $25 million. Under this
agreement, $12.0 million was outstanding at December 31, 2002.
This subsidiary intends to renew this credit agreement, which
expires June 30, 2003. Centennial has guaranteed this short-term
credit agreement.
In order to borrow under the credit facility, the subsidiary
must be in compliance with the applicable covenants and certain
other conditions. The significant covenants include limitation on
sale of assets and limitation on loans and investments. This
subsidiary was in compliance with these covenants and met the
required conditions at December 31, 2002. In the event this
subsidiary does not comply with the applicable covenants and other
conditions, alternative sources of funding may need to be pursued.
Williston Basin Interstate Pipeline Company
Williston Basin has an uncommitted long-term master shelf
agreement that allows for borrowings of up to $100 million. Under
the terms of the master shelf agreement, $30.0 million was
outstanding at December 31, 2002.
In order to borrow under Williston Basin's uncommitted long-
term master shelf agreement, it must be in compliance with the
applicable covenants and certain other conditions. The
significant covenants include limitation on consolidated
indebtedness, limitation on priority debt, limitation on sale of
assets and limitation on investments. Williston Basin was in
compliance with these covenants and met the required conditions at
December 31, 2002. In the event Williston Basin does not comply
with the applicable covenants and other conditions, alternative
sources of funding may need to be pursued.
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 8 and 17 of Notes to Consolidated Financial Statements. At
December 31, 2002, the Company's commitments under these
obligations were as follows:
There-
2003 2004 2005 2006 2007 after Total
(In millions)
Long-term debt $ 22.1 $173.8 $ 70.3 $100.2 $105.4 $369.8 $ 841.6
Operating leases 19.3 14.3 11.2 7.8 4.3 21.3 78.2
Purchase
commitments 171.3 55.4 43.1 37.0 27.6 130.4 464.8
$212.7 $243.5 $124.6 $145.0 $137.3 $521.5 $1,384.6
Certain subsidiaries of the Company have financial guarantees
outstanding at December 31, 2002. These guarantees as of December
31, 2002, are approximately $47.6 million, of which approximately
$24.9 million pertain to Centennial's guarantee of certain
obligations in connection with the natural gas-fired electric
generation station in Brazil. For more information on these
guarantees, see Notes 2 and 17 of Notes to Consolidated Financial
Statements. As of December 31, 2002, with respect to these
guarantees, there was approximately $43.2 million outstanding
through 2003, $1.4 million outstanding through 2004 and $3.0
million outstanding thereafter. These guarantees are not
reflected in the consolidated financial statements.
As of December 31, 2002, Centennial was contingently liable for
performance of certain of its subsidiaries under approximately
$200 million of surety bonds. These bonds are principally for
construction contracts and reclamation obligations of these
subsidiaries, entered into in the normal course of business.
Centennial indemnifies the respective surety bond companies
against any exposure under the bonds. A large portion of these
contingent commitments expire in 2003, however Centennial will
likely continue to enter into surety bonds for its subsidiaries in
the future.
Approval of audit and nonaudit services
During the fourth quarter of 2002, the Company's Audit
Committee pre-approved certain audit services relating to comfort
letters and consents in connection with registration statements
and other SEC required filings and audit reviews in connection
with such filings, audit reviews in connection with business
combinations, and additional audit services required in connection
with quarterly reviews and annual audits. The Audit Committee
also approved certain nonaudit services, relating to tax services
in connection with domestic and international operations, and
training on accounting and SEC compliance.
Effects of Inflation
Inflation did not have a significant effect on the Company's
operations in 2002, 2001 or 2000.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to the impact of market fluctuations
associated with commodity prices, interest rates and foreign
currency. The Company has policies and procedures to assist in
controlling these market risks and utilizes derivatives to manage
a portion of its risk.
The Company's policy allows the use of derivative instruments
as part of an overall energy price, foreign currency and interest
rate risk management program to efficiently manage and minimize
commodity price, foreign currency and interest rate risk. The
Company's policy prohibits the use of derivative instruments for
speculating to take advantage of market trends and conditions and
the Company has procedures in place to monitor compliance with its
policies. The Company is exposed to credit-related losses in
relation to derivative instruments in the event of nonperformance
by counterparties. The Company's policy requires settlement of
natural gas and oil price derivative instruments monthly, and that
all interest rate derivative transactions must be settled over a
period that will not exceed 90 days, and that any foreign currency
derivative transaction settlement periods may not exceed a 12-
month period. The Company has policies and procedures that
management believes minimize credit-risk exposure. These policies
and procedures include an evaluation of potential counterparties'
credit ratings and credit exposure limitations. Accordingly, the
Company does not anticipate any material effect to its financial
position or results of operations as a result of nonperformance by
counterparties.
In the event a derivative instrument being accounted for as a
cash flow hedge does not qualify for hedge accounting because it
is no longer highly effective in offsetting changes in cash flows
of a hedged item; or if the derivative instrument expires or is
sold, terminated or exercised; or if management determines that
designation of the derivative instrument as a hedge instrument is
no longer appropriate, hedge accounting will be discontinued, and
the derivative instrument would continue to be carried at fair
value with changes in its fair value recognized in earnings. In
these circumstances, the net gain or loss at the time of
discontinuance of hedge accounting would remain in other
accumulated comprehensive income (loss) until the period or
periods during which the hedged forecasted transaction affects
earnings, at which time the net gain or loss would be reclassified
into earnings. In the event a cash flow hedge is discontinued
because it is unlikely that a forecasted transaction will occur,
the derivative instrument would continue to be carried on the
balance sheet at its fair value, and gains and losses that had
accumulated in other comprehensive income (loss) would be
recognized immediately in earnings. In the event of a sale,
termination or extinguishment of a foreign currency derivative,
the resulting gain or loss would be recognized immediately in
earnings. The Company's policy requires approval to terminate a
derivative instrument prior to its original maturity.
Commodity price risk --
A subsidiary of the Company utilizes natural gas and oil price
swap and collar agreements to manage a portion of the market risk
associated with fluctuations in the price of natural gas and oil
on the subsidiary's forecasted sales of natural gas and oil
production. Each of the natural gas and oil price swap and collar
agreements were designated as a hedge of the forecasted sale of
natural gas and oil production.
On an ongoing basis, the balance sheet is adjusted to reflect
the current fair market value of the swap and collar agreements.
The related gains or losses on these agreements are recorded in
common stockholders' equity as a component of other comprehensive
income (loss). At the date the underlying transaction occurs, the
amounts accumulated in other comprehensive income (loss) are
reported in the Consolidated Statements of Income. To the extent
that the hedges are not effective, the ineffective portion of the
changes in fair market value is recorded directly in earnings.
The following table summarizes hedge agreements entered into by
a wholly owned subsidiary of the Company, as of December 31, 2002.
These agreements call for the subsidiary to receive fixed prices
and pay variable prices.
(Notional amount and fair value in thousands)
Weighted
Average Notional
Fixed Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas swap
agreements maturing
in 2003 $ 3.96 1,186 $(731)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2003 $3.33/$3.89 22,365 $(6,256)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per barrel) (In barrels) Fair Value
Oil collar agreements
maturing in 2003 $24.50/$27.62 639 $(457)
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
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. As of
December 31, 2002, the Company also has outstanding 13,000 shares
of 5.10% Series preferred stock subject to mandatory redemption.
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 following table shows the amount of debt, including
current portion, and related weighted average interest rates, both
by expected maturity dates as well as the aggregate annual sinking
fund amount applicable to preferred stock subject to mandatory
redemption and the related dividend rate, as of December 31, 2002.
Weighted average variable rates are based on forward rates as of
December 31, 2002.
There- Fair
2003 2004 2005 2006 2007 after Total Value
(Dollars in millions)
Long-term debt:
Fixed rate $22.1 $ 21.9 $70.3 $100.2 $105.4 $369.8 $689.7 $742.7
Weighted average
interest rate 7.4% 6.6% 8.0% 6.5% 8.2% 6.6% 7.0% -
Variable rate - $151.9 - - - - $151.9 $145.4
Weighted average
interest rate - 1.5% - - - - 1.5% -
Preferred stock
subject to mandatory
redemption $ .1 $ .1 $ .1 $ .1 $ .1 $ .8 $ 1.3 $ 1.2
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 5 and 6 of Notes
to Consolidated Financial Statements.
Foreign currency risk --
A subsidiary of the Company has a 49 percent equity investment
in a 200-megawatt natural gas-fired electric generation project
(Project) in Brazil, which has a portion of its borrowings and
payables denominated in U.S. dollars. The subsidiary has exposure
to currency exchange risk as a result of fluctuations in currency
exchange rates between the U.S. dollar and the Brazilian real.
The functional currency for the Project is the Brazilian real.
For further information on this investment, see Note 2 of Notes to
Consolidated Financial Statements.
The subsidiary's equity income from this Brazilian investment
is impacted by fluctuations in currency exchange rates on
transactions denominated in a currency other than the Brazilian
real, including the effects of changes in currency exchange rates
with respect to the Project's U.S. dollar denominated obligations,
excluding a U.S. dollar denominated loan from the subsidiary as
discussed below. At December 31, 2002, these U.S. dollar
denominated obligations approximated $47.5 million. If, for
example, the value of the Brazilian real decreased in relation to
the U.S. dollar by 10 percent, the subsidiary, with respect to its
interest in the Project, would record a foreign currency
transaction loss in net income of approximately $2.1 million based
on the above U.S. dollar denominated obligations at December 31,
2002. The Project also had US$27.6 million Brazilian real
denominated obligations at December 31, 2002.
Adjustments attributable to the translation from the Brazilian
real to the U.S. dollar for assets, liabilities, revenues and
expenses were recorded in accumulated other comprehensive income
at December 31, 2002.
The Project also had U.S. dollar denominated borrowings payable
to the subsidiary of $20.0 million at December 31, 2002. Foreign
currency translation adjustments on the Project's borrowings
payable to the subsidiary are recorded in accumulated other
comprehensive income.
The subsidiary's investment in this Project at December 31,
2002, was $27.8 million. Centennial has guaranteed Project
obligations and loans of approximately $24.9 million as of
December 31, 2002.
The subsidiary is managing a portion of its foreign currency
exchange risk through contractual provisions, that are largely
indexed to the U.S. dollar, contained in the Project's power
purchase agreement with Petrobras. On August 12, 2002, the
subsidiary entered into a foreign currency collar agreement for a
notional amount of $21.3 million, with a fixed price floor of
R$3.10 and a fixed price ceiling of R$3.40, to manage a portion of
its foreign currency risk. The collar agreement settled on
February 3, 2003, at a favorable settlement amount of
approximately $760,000 (pretax). Gains or losses on this derivative
instrument are recorded in earnings each period. The fair value
of the foreign currency collar agreement at December 31, 2002,
was approximately $903,000 ($566,000 after tax). From time to
time, derivative instruments may be utilized to manage a portion
of the foreign currency risk.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to Pages 41 through 79 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
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Reference is made to Pages 2 through 5 and 13 through 14 of the
Company's Proxy Statement dated March 7, 2003 (Proxy Statement),
which is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Reference is made to Pages 6 through 9 and 16 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 AND RELATED STOCKHOLDER MATTERS
Equity Compensation Plan Information
The following table includes information as of December 31,
2002 with respect to the Company's equity compensation plans.
These plans include the 1992 Key Employee Stock Option Plan
(KESOP), the 1997 Non-Employee Director Long-Term Incentive Plan
(1997 Director Plan), the 1997 Executive Long-Term Incentive Plan
(1997 LTIP), the Non-Employee Director Stock Compensation Plan
(Director Compensation Plan), the 1998 Option Award Program (All
Employee Plan) and the Group Genius Innovation Plan (Group Genius
Plan).
(c)
Number of
securities
(a) remaining
Number of (b) available for
securities to Weighted- future issuance
be issued upon average under equity
exercise of exercise price compensation
outstanding of outstanding plans (excluding
options, options, securities
warrants and warrants and reflected in
Plan Category rights rights column (a))
Equity
compensation
plans approved
by
stockholders (1) 2,170,595 $27.49 4,510,084 (2)(3)
Equity
compensation
plans not
approved by
stockholders (4) 1,070,250 $28.62 774,870 (5)
Total 3,240,845 $27.87 5,284,954
(1) Consists of the KESOP, the 1997 Director Plan, the 1997 LTIP
and the Director Compensation Plan.
(2) In addition to being available for future issuance upon
exercise of options, 153,000 shares under the 1997 Director Plan
may instead be issued in connection with stock appreciation
rights, restricted stock, performance units, performance shares or
other equity-based awards, and 4,311,628 shares under the
Company's 1997 LTIP may instead be issued in connection with stock
appreciation rights, restricted stock, performance units,
performance shares or other equity-based awards.
(3) This amount also includes 45,456 shares available for issuance
under the Director Compensation Plan. Under the Director
Compensation Plan, in addition to a cash retainer, non-employee
directors are awarded 1,000 shares following the date of the
Company's annual meeting of stockholders. Additionally, a non-
employee director may acquire additional shares under the
Director Compensation Plan in lieu of receiving the cash portion
of the director's retainer or fees.
(4) Consists of the All Employee Plan and the Group Genius Plan.
(5) In addition to being available for future issuance upon
exercise of options, 99,600 shares under the Group Genius Plan may
instead be issued in connection with stock appreciation rights,
restricted stock, restricted stock units, performance units,
performance stock or other equity-based awards.
The following two equity compensation plans have not been
approved by the Company's stockholders.
The All Employee Plan
The All Employee Plan is a broad-based plan adopted by the
Board of Directors, effective February 12, 1998. The plan permits
the grant of nonqualified stock options to employees of the
Company and its subsidiaries. The maximum number of shares that
may be issued under the plan is 1,875,000. Shares granted may be
authorized but unissued shares, treasury shares, or shares
purchased on the open market. Option exercise prices are equal to
the market value of the Company's shares on the date of the option
grant. Optionees receive dividend equivalents on their options,
with any credited dividends paid in cash to the optionee if the
option vests, or forfeited if the option is forfeited. Vested
options remain exercisable for one year following termination of
employment due to death or disability and for three months
following termination of employment for any other reason.
Unvested options are forfeited upon termination of employment.
Subject to the terms and conditions of the plan, the plan's
administrative committee determines the number of shares subject
to options granted to each participant and the other terms and
conditions pertaining to such options, including vesting
provisions. All options become immediately exercisable in the
event of a change in control of the Company.
In 1998, 150 options (adjusted for the three-for-two stock
split in July 1998) were granted to each of approximately 2,200
employees. No officers received grants. These options vested on
March 2, 2001. In 2001, 200 options were granted to each of
approximately 5,900 employees. No officers received grants.
These options will vest on February 13, 2004. As of December 31,
2002, options covering 1,070,250 shares of common stock were
outstanding under the plan. 675,270 shares remained available for
future grant and options covering 129,480 shares had been
exercised.
The Group Genius Plan
The Group Genius Plan was adopted by the Board of Directors,
effective May 17, 2001, to encourage employees to share ideas for
new business directions for the Company and to reward them when
the idea becomes profitable. Employees of the Company and its
subsidiaries who are selected by the plan's administrative
committee are eligible to participate in the plan. Officers and
directors are not eligible to participate. The plan permits the
granting of nonqualified stock options, stock appreciation rights,
restricted stock, restricted stock units, performance units,
performance stock and other awards. The maximum number of shares
that may be issued under the plan is 100,000. Shares granted
under the plan may be authorized but unissued shares, treasury
shares or shares purchased on the open market. Restricted stock-
holders have voting rights and, unless determined otherwise by the
plan's administrative committee, receive dividends paid on the
restricted stock. Dividend equivalents payable in cash may be
granted with respect to options and performance shares. The
plan's administrative committee determines the number of shares or
units subject to awards, and the other terms and conditions of the
awards, including vesting provisions and the effect of employment
termination. Upon a change in control of the Company, all options
and stock appreciation rights become immediately vested and
exercisable, all restricted stock becomes immediately vested, all
restricted stock units become immediately vested and are paid out
in cash, and target payout opportunities under all performance
units, performance stock, and other awards are deemed to be fully
earned, with awards denominated in stock paid out in shares and
awards denominated in units paid out in cash. In March 2002, 100
shares of stock were granted to each of three employees and 50
shares of stock were granted to each of two employees.
Reference is made to Pages 15 and 16 of the Proxy Statement,
which is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14. CONTROLS AND PROCEDURES
The following information includes the evaluation of disclosure
controls and procedures by the Company's chief executive officer
and the chief financial officer, along with any significant
changes in internal controls of the Company.
Evaluation of disclosure controls and procedures
The term "disclosure controls and procedures" is defined in
Rules 13a-14(c) and 15d-14(c) of the Securities Exchange Act of
1934 (Exchange Act). These rules refer to the controls and other
procedures of a company that are designed to ensure that
information required to be disclosed by a company in the reports
that it files under the Exchange Act is recorded, processed,
summarized and reported within required time periods. The
Company's chief executive officer and chief financial officer have
evaluated the effectiveness of the Company's disclosure controls
and procedures as of a date within 90 days before the filing of
this Annual Report on Form 10-K (Evaluation Date), and, they have
concluded that, as of the Evaluation Date, such controls and
procedures were effective to accomplish those tasks.
Changes in internal controls
The Company maintains a system of internal accounting controls
that are designed to provide reasonable assurance that the
Company's transactions are properly authorized, the Company's
assets are safeguarded against unauthorized or improper use, and
the Company's transactions are properly recorded and reported to
permit preparation of the Company's financial statements in
conformity with generally accepted accounting principles in the
United States of America. There were no significant changes in
the Company's internal controls or in other factors that could
significantly affect the Company's internal controls subsequent
to the Evaluation Date, nor were there any significant deficiencies
or material weaknesses in the Company's internal controls.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) Financial Statements, Financial Statement Schedules and
Exhibits
Index to Financial Statements and Financial Statement
Schedules
Page
1. Financial Statements:
Independent Auditors' Report for the year ended
December 31, 2002 *
Report of Independent Public Accountants for the
years ended December 31, 2001 and 2000 *
Consolidated Statements of Income for each
of the three years in the period ended
December 31, 2002 *
Consolidated Balance Sheets at December 31,
2002 and 2001 *
Consolidated Statements of Common Stockholders'
Equity for each of the three years in the
period ended December 31, 2002 *
Consolidated Statements of Cash Flows for
each of the three years in the period ended
December 31, 2002 *
Notes to Consolidated Financial Statements *
2. Financial Statement Schedules:
Independent Auditors' Report on Financial
Statement Schedule for the year ended
December 31, 2002 **
Report of Independent Public Accountants on
Financial Statement Schedule for the years
ended December 31, 2001 and 2000 **
Schedule II - Consolidated Valuation and
Qualifying Accounts for the years ended
December 31, 2002, 2001 and 2000 **
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 2002 are hereby incorporated by reference.
With the exception of the pages referred to in Items 6 and
8, the Company's Annual Report to Stockholders for 2002 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, filed as Exhibit
3(a) to Form 10-Q for the quarter ended
June 30, 2002, in File No. 1-3480 *
3(b) By-laws of the Company, as amended,
filed as Exhibit 4(b) to Form S-8 on
October 1, 2001, in Registration
No. 333-70622 *
3(c) Certificate of Designations of Series B
Preference Stock of the Company, as
amended, filed as Exhibit 3(a) to
Form 10-Q for the quarter ended
September 30, 2002, in File No. 1-3480 *
4(a) Indenture of Mortgage, dated as of May 1,
1939, as restated in the Forty-Fifth
Supplemental Indenture, dated as of
April 21, 1992, and the Forty-Sixth
through Forty-Ninth Supplements thereto
between the Company and the New York Trust
Company (The Bank of New York, successor
Corporate Trustee) and A. C. Downing
(Douglas J. MacInnes, successor Co-
Trustee), filed as Exhibit 4(a) in
Registration No. 33-66682; and Exhibits
4(e), 4(f) and 4(g) in Registration
No. 33-53896; and Exhibit 4(c)(i) in
Registration No. 333-49472 *
4(b) 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, filed as Exhibit 10(a) to
Form 10-K for the year ended December 31,
2001, in File No. 1-3480 *
+ 10(b) 1992 Key Employee Stock Option Plan, as
amended **
+ 10(c) Supplemental Income Security Plan, as
amended **
+ 10(d) Directors' Compensation Policy, as amended,
filed as Exhibit 10(a) to Form 10-Q for
the quarter ended March 31, 2002, in File
No. 1-3480 *
+ 10(e) Deferred Compensation Plan for Directors,
as amended **
+ 10(f) Non-Employee Director Stock Compensation
Plan, as amended, filed as Exhibit 10(f)
to Form 10-K for the year ended
December 31, 2001, in File No. 1-3480 *
+ 10(g) 1997 Non-Employee Director Long-Term
Incentive Plan, as amended, filed as
Exhibit 10(d) to Form 10-Q for the quarter
ended June 30, 2000, in File No. 1-3480 *
+ 10(h) 1997 Executive Long-Term Incentive Plan,
as amended, filed as Exhibit 10(a) to
Form 10-Q for the quarter ended
March 31, 2001, in File No. 1-3480 *
+ 10(i) Change of Control Employment Agreement
between the Company and John K. Castleberry,
filed as Exhibit 10(a) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(j) Change of Control Employment Agreement
between the Company and Cathleen M.
Christopherson, filed as Exhibit 10(b) to
Form 10-Q for the quarter ended
September 30, 2002, in File No. 1-3480 *
+ 10(k) Change of Control Employment Agreement
between the Company and Richard A. Espeland,
filed as Exhibit 10(c) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(l) Change of Control Employment Agreement
between the Company and Terry D. Hildestad,
filed as Exhibit 10(d) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(m) Change of Control Employment Agreement
between the Company and Lester H. Loble, II,
filed as Exhibit 10(e) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(n) Change of Control Employment Agreement
between the Company and Vernon A. Raile,
filed as Exhibit 10(f) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(o) Change of Control Employment Agreement
between the Company and Warren L. Robinson,
filed as Exhibit 10(g) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(p) Change of Control Employment Agreement
between the Company and William E. Schneider,
filed as Exhibit 10(h) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(q) Change of Control Employment Agreement
between the Company and Ronald D. Tipton,
filed as Exhibit 10(i) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(r) Change of Control Employment Agreement
between the Company and Martin A. White,
filed as Exhibit 10(j) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(s) Change of Control Employment Agreement
between the Company and Robert E. Wood,
filed as Exhibit 10(k) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(t) Separation Agreement and Release between
the Company and Douglas C. Kane **
+ 10(u) 1998 Option Award Program **
+ 10(v) Group Genius Innovation Plan **
12 Computation of Ratio of Earnings to Fixed
Charges and Combined Fixed Charges and
Preferred Stock Dividends **
13 Selected financial data, financial
statements and supplementary data as
contained in the Annual Report to
Stockholders for 2002; Independent
Auditors' Report on Financial Statement
Schedule for the year ended December 31,
2002; Report of Independent Public
Accountants on Financial Statement
Schedule for the years ended December 31,
2001 and 2000; and Financial Statement
Schedule II **
21 Subsidiaries of MDU Resources Group, Inc. **
23 Consent of Independent Auditors **
99 Statement Furnished Pursuant to
Section 906 of Sarbanes - Oxley Act
of 2002 **
________________________
* Incorporated herein by reference as indicated.
** Filed herewith.
+ Management contract, compensatory plan or arrangement
required to be filed as an exhibit to this form pursuant to
Item 15(c) of this report.
(b) Reports on Form 8-K
Form 8-K was filed on October 23, 2002. Under Item 5 --
Other Events, the Company reported the press release issued
October 22, 2002, regarding earnings for the quarter ended
September 30, 2002.
Form 8-K was filed on November 5, 2002. Under Item 5 --
Other Events and Item 7 -- Financial Statements and Exhibits,
the Company reported the purchase of 213-megawatts of natural
gas-fired electric generating facilities.
Form 8-K was filed on November 18, 2002. Under Item 7 --
Financial Statements and Exhibits, the Company filed an
Underwriting Agreement relating to a public offering of the
Company's common stock.
Form 8-K was filed on December 23, 2002. Under Item 5 --
Other Events and Item 7 -- Financial Statements and Exhibits,
the Company reported the purchase of a 66.6-megawatt wind-
powered electric generation facility.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, as amended, the registrant has
duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
MDU RESOURCES GROUP, INC.
Date: February 28, 2003 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, as amended, this report has been signed below by the
following persons on behalf of the registrant in the capacities and
on the date indicated.
Signature Title Date
/s/ Martin A. White Chief Executive February 28, 2003
Martin A. White (Chairman of the Board, Officer
President and Chief Executive Officer) and Director
/s/ Warren L. Robinson Chief Financial February 28, 2003
Warren L. Robinson (Executive Vice Officer
President, Treasurer and Chief Financial
Officer)
/s/ Vernon A. Raile Chief Accounting February 28, 2003
Vernon A. Raile (Senior Vice President, Officer
Controller and Chief Accounting Officer)
/s/ Harry J. Pearce Lead Director February 28, 2003
Harry J. Pearce
Director
Bruce R. Albertson
/s/ Thomas Everist Director February 28, 2003
Thomas Everist
/s/ Dennis W. Johnson Director February 28, 2003
Dennis W. Johnson
/s/ Robert L. Nance Director February 28, 2003
Robert L. Nance
/s/ John L. Olson Director February 28, 2003
John L. Olson
/s/ Homer A. Scott, Jr. Director February 28, 2003
Homer A. Scott, Jr.
/s/ Joseph T. Simmons Director February 28, 2003
Joseph T. Simmons
/s/ Sister Thomas Welder Director February 28, 2003
Sister Thomas Welder
10-K CERTIFICATION
I, Martin A. White, certify that:
1. I have reviewed this annual report on Form 10-K of MDU
Resources Group, Inc.;
2. Based on my knowledge, this annual report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in
light of the circumstances under which such statements were
made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition,
results of operations and cash flows of the registrant as
of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and have:
a. designed such disclosure controls and procedures to
ensure that material information relating to the
registrant, including its consolidated subsidiaries, is
made known to us by others within those entities,
particularly during the period in which this annual
report is being prepared;
b. evaluated the effectiveness of the registrant's
disclosure controls and procedures as of a date within 90
days prior to the filing date of this annual report (the
"Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the
equivalent functions):
a. all significant deficiencies in the design or operation
of internal controls which could adversely affect the
registrant's ability to record, process, summarize and
report financial data and have identified for the
registrant's auditors any material weaknesses in internal
controls; and
b. any fraud, whether or not material, that involves
management or other employees who have a significant role
in the registrant's internal controls; and
6. The registrant's other certifying officer and I have
indicated in this annual report whether there were
significant changes in internal controls or in other factors
that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies
and material weaknesses.
Date: February 28, 2003 /s/ Martin A. White
Martin A. White
Chairman of the Board, President
and Chief Executive Officer
10-K CERTIFICATION
I, Warren L. Robinson, certify that:
1. I have reviewed this annual report on Form 10-K of MDU
Resources Group, Inc.;
2. Based on my knowledge, this annual report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in
light of the circumstances under which such statements were
made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition,
results of operations and cash flows of the registrant as
of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and have:
a. designed such disclosure controls and procedures to
ensure that material information relating to the
registrant, including its consolidated subsidiaries, is
made known to us by others within those entities,
particularly during the period in which this annual
report is being prepared;
b. evaluated the effectiveness of the registrant's
disclosure controls and procedures as of a date within 90
days prior to the filing date of this annual report (the
"Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the
equivalent functions):
a. all significant deficiencies in the design or operation
of internal controls which could adversely affect the
registrant's ability to record, process, summarize and
report financial data and have identified for the
registrant's auditors any material weaknesses in internal
controls; and
b. any fraud, whether or not material, that involves
management or other employees who have a significant role
in the registrant's internal controls; and
6. The registrant's other certifying officer and I have
indicated in this annual report whether there were
significant changes in internal controls or in other factors
that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies
and material weaknesses.
Date: February 28, 2003 /s/ Warren L. Robinson
Warren L. Robinson
Executive Vice President, Treasurer
and Chief Financial Officer