Back to GetFilings.com
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